In situ thermal processing of a hydrocarbon containing formation to produce hydrocarbon fluids and synthesis gas

ABSTRACT

A hydrocarbon containing formation may be treated using an in situ thermal process. A mixture of hydrocarbons, H 2 , and/or other formation fluids may be produced from the formation. Heat may be applied to the formation to raise a temperature of a portion of the formation to a pyrolysis temperature. After pyrolysis, the portion may be heated to a synthesis gas production temperature. A synthesis gas producing fluid may be introduced into the portion to generate synthesis gas. Synthesis gas may be produced from the formation in a batch manner or in a substantially continuous manner.

PRIORITY CLAIM

[0001] This application claims priority to U.S. Provisional ApplicationNo. 60/199,215 entitled “In Situ Energy Recovery,” filed Apr. 24, 2000,U.S. Provisional Application No. 60/199,214 entitled “In Situ EnergyRecovery From Coal,” filed Apr. 24, 2000, and U.S. ProvisionalApplication No. 60/199,213 entitled “Emissionless Energy Recovery FromCoal,” filed Apr. 24, 2000. The above-referenced provisionalapplications are hereby incorporated by reference as if fully set forthherein.

BACKGROUND OF THE INVENTION

[0002] 1. Field of the Invention

[0003] The present invention relates generally to methods and systemsfor production of hydrocarbons, hydrogen, and/or other products fromvarious hydrocarbon containing formations. Certain embodiments relate toin situ conversion of hydrocarbons to produce hydrocarbons, hydrogen,and/or novel product streams from underground hydrocarbon containingformations.

[0004] 2. Description of Related Art

[0005] Hydrocarbons obtained from subterranean (e.g., sedimentary)formations are often used as energy resources, as feedstocks, and asconsumer products. Concerns over depletion of available hydrocarbonresources have led to development of processes for more efficientrecovery, processing and/or use of available hydrocarbon resources. Insitu processes may be used to remove hydrocarbon materials fromsubterranean formations. Chemical and/or physical properties ofhydrocarbon material within a subterranean formation may need to bechanged to allow hydrocarbon material to be more easily removed from thesubterranean formation. The chemical and physical changes may include insitu reactions that produce removable fluids, composition changes,solubility changes, phase changes, and/or viscosity changes of thehydrocarbon material within the formation. A fluid may be, but is notlimited to, a gas, a liquid, an emulsion, a slurry and/or a stream ofsolid particles that has flow characteristics similar to liquid flow.

[0006] Examples of in situ processes utilizing downhole heaters areillustrated in U.S. Pat. No. 2,634,961 to Ljungstrom, U.S. Pat. No.2,732,195 to Ljungstrom, U.S. Pat. No. 2,780,450 to Ljungstrom, U.S.Pat. No. 2,789,805 to Ljungstrom, U.S. Pat. No. 2,923,535 issued toLjungstrom, and U.S. Pat. No. 4,886,118 to Van Meurs et al., each ofwhich is incorporated by reference as if fully set forth herein.

[0007] Application of heat to oil shale formations is described in U.S.Pat. No. 2,923,535 to Ljungstrom and U.S. Pat. No. 4,886,118 to VanMeurs et al., both of which are incorporated by reference as if fullyset forth herein. Heat may be applied to the oil shale formation topyrolyze kerogen within the oil shale formation. The heat may alsofracture the formation to increase permeability of the formation. Theincreased permeability may allow formation fluid to travel to aproduction well where the fluid is removed from the oil shale formation.In some processes disclosed by Ljungstrom, for example, an oxygencontaining gaseous medium is introduced to a permeable stratum,preferably while still hot from a preheating step, to initiatecombustion.

[0008] A heat source may be used to heat a subterranean formation.Electrical heaters may be used to heat the subterranean formation byradiation and/or conduction. An electrical heater may resistively heatan element. U.S. Pat. No. 2,548,360 to Germain, which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement placed within a viscous oil within a wellbore. The heaterelement heats and thins the oil to allow the oil to be pumped from thewellbore. U.S. Pat. No. 4,716,960 to Eastlund et al., which isincorporated by reference as if fully set forth herein, describeselectrically heating tubing of a petroleum well by passing a relativelylow voltage current through the tubing to prevent formation of solids.U.S. Pat. No. 5,065,818 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement that is cemented into a well borehole without a casingsurrounding the heating element.

[0009] U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporatedby reference as if fully set forth herein, describes an electricalheating element that is positioned within a casing. The heating elementgenerates radiant energy that heats the casing. A granular solid fillmaterial may be placed between the casing and the formation. The casingmay conductively heat the fill material, which in turn conductivelyheats the formation.

[0010] U.S. Pat. No. 4,570,715 to Van Meurs et al., which isincorporated by reference as if fully set forth herein, describes anelectrical heating element. The heating element has an electricallyconductive core, a surrounding layer of insulating material, and asurrounding metallic sheath. The conductive core may have a relativelylow resistance at high temperatures. The insulating material may haveelectrical resistance, compressive strength and heat conductivityproperties that are relatively high at high temperatures. The insulatinglayer may inhibit arcing from the core to the metallic sheath. Themetallic sheath may have tensile strength and creep resistanceproperties that are relatively high at high temperatures.

[0011] U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement having a copper-nickel alloy core.

[0012] Combustion of a fuel may be used to heat a formation. Combustinga fuel to heat a formation may be more economical than using electricityto heat a formation. Several different types of heaters may use fuelcombustion as a heat source that heats a formation. The combustion maytake place in the formation, in a well and/or near the surface.Combustion in the formation may be a fireflood. An oxidizer may bepumped into the formation. The oxidizer may be ignited to advance a firefront towards a production well. Oxidizer pumped into the formation mayflow through the formation along fracture lines in the formation.Ignition of the oxidizer may not result in the fire front flowinguniformly through the formation.

[0013] A flameless combustor may be used to combust a fuel within awell. U.S. Pat. No. 5,255,742 to Mikus, U.S. Pat. No. 5,404,952 toVinegar et al., U.S. Pat. No. 5,862,858 to Wellington et al., and U.S.Pat. No. 5,899,269 to Wellington et al., which are incorporated byreference as if fully set forth herein, describe flameless combustors.Flameless combustion may be accomplished by preheating a fuel andcombustion air to a temperature above an auto-ignition temperature ofthe mixture. The fuel and combustion air may be mixed in a heating zoneto combust. In the heating zone of the flameless combustor, a catalyticsurface may be provided to lower the auto-ignition temperature of thefuel and air mixture.

[0014] Heat may be supplied to a formation from a surface heater. Thesurface heater may produce combustion gases that are circulated throughwellbores to heat the formation. Alternately, a surface burner may beused to heat a heat transfer fluid that is passed through a wellbore toheat the formation. Examples of fired heaters, or surface burners thatmay be used to heat a subterranean formation, are illustrated in U.S.Pat. No. 6,056,057 to Vinegar et al. and U.S. Pat. No. 6,079,499 toMikus et al., which are both incorporated by reference as if fully setforth herein.

[0015] Coal is often mined and used as a fuel within an electricitygenerating power plant. Most coal that is used as a fuel to generateelectricity is mined. A significant number of coal containing formationsare, however, not suitable for economical mining. For example, miningcoal from steeply dipping coal seams, from relatively thin coal seams(e.g., less than about 1 meter thick), and/or from deep coal seams maynot be economically feasible. Deep coal seams include coal seams thatare at, or extend to, depths of greater than about 3000 feet (about 914m) below surface level. The energy conversion efficiency of burning coalto generate electricity is relatively low, as compared to fuels such asnatural gas. Also, burning coal to generate electricity often generatessignificant amounts of carbon dioxide, oxides of sulfur, and oxides ofnitrogen that are released into the atmosphere.

[0016] Synthesis gas may be produced in reactors or in situ within asubterranean formation. Synthesis gas may be produced within a reactorby partially oxidizing methane with oxygen. In situ production ofsynthesis gas may be economically desirable to avoid the expense ofbuilding, operating, and maintaining a surface synthesis gas productionfacility. U.S. Pat. No. 4,250,230 to Terry, which is incorporated byreference as if fully set forth herein, describes a system for in situgasification of coal. A subterranean coal seam is burned from a firstwell towards a production well. Methane, hydrocarbons, H₂, CO, and otherfluids may be removed from the formation through the production well.The H₂ and CO may be separated from the remaining fluid. The H₂ and COmay be sent to fuel cells to generate electricity.

[0017] U.S. Pat. No. 4,057,293 to Garrett, which is incorporated byreference as if fully set forth herein, discloses a process forproducing synthesis gas. A portion of a rubble pile is burned to heatthe rubble pile to a temperature that generates liquid and gaseoushydrocarbons by pyrolysis. After pyrolysis, the rubble is furtherheated, and steam or steam and air are introduced to the rubble pile togenerate synthesis gas.

[0018] U.S. Pat. No. 5,554,453 to Steinfeld et al., which isincorporated by reference as if fully set forth herein, describes an exsitu coal gasifier that supplies fuel gas to a fuel cell. The fuel cellproduces electricity. A catalytic burner is used to burn exhaust gasfrom the fuel cell with an oxidant gas to generate heat in the gasifier.

[0019] Carbon dioxide may be produced from combustion of fuel and frommany chemical processes. Carbon dioxide may be used for variouspurposes, such as, but not limited to, a feed stream for a dry iceproduction facility, supercritical fluid in a low temperaturesupercritical fluid process, a flooding agent for coal beddemethanation, and a flooding agent for enhanced oil recovery. Althoughsome carbon dioxide is productively used, many tons of carbon dioxideare vented to the atmosphere.

[0020] Retorting processes for oil shale may be generally divided intotwo major types: aboveground (surface) and underground (in situ).Aboveground retorting of oil shale typically involves mining andconstruction of metal vessels capable of withstanding high temperatures.The quality of oil produced from such retorting may typically be poor,thereby requiring costly upgrading. Aboveground retorting may alsoadversely affect environmental and water resources due to mining,transporting, processing and/or disposing of the retorted material. ManyU.S. patents have been issued relating to aboveground retorting of oilshale. Currently available aboveground retorting processes include, forexample, direct, indirect, and/or combination heating methods.

[0021] In situ retorting typically involves retorting oil shale withoutremoving the oil shale from the ground by mining. “Modified” in situprocesses typically require some mining to develop underground retortchambers. An example of a “modified” in situ process includes a methoddeveloped by Occidental Petroleum that involves mining approximately 20%of the oil shale in a formation, explosively rubblizing the remainder ofthe oil shale to fill up the mined out area, and combusting the oilshale by gravity stable combustion in which combustion is initiated fromthe top of the retort. Other examples of “modified” in situ processesinclude the “Rubble In Situ Extraction” (“RISE”) method developed by theLawrence Livermore Laboratory (“LLL”) and radio-frequency methodsdeveloped by IIT Research Institute (“IITRI”) and LLL, which involvetunneling and mining drifts to install an array of radio-frequencyantennas in an oil shale formation.

[0022] Obtaining permeability within an oil shale formation (e.g.,between injection and production wells) tends to be difficult becauseoil shale is often substantially impermeable. Many methods haveattempted to link injection and production wells, including: hydraulicfracturing such as methods investigated by Dow Chemical and LaramieEnergy Research Center; electrical fracturing (e.g., by methodsinvestigated by Laramie Energy Research Center); acid leaching oflimestone cavities (e.g., by methods investigated by Dow Chemical);steam injection into permeable nahcolite zones to dissolve the nahcolite(e.g., by methods investigated by Shell Oil and Equity Oil); fracturingwith chemical explosives (e.g., by methods investigated by Talley EnergySystems); fracturing with nuclear explosives (e.g., by methodsinvestigated by Project Bronco); and combinations of these methods. Manyof such methods, however, have relatively high operating costs and lacksufficient injection capacity.

[0023] An example of an in situ retorting process is illustrated in U.S.Pat. No. 3,241,611 to Dougan, assigned to Equity Oil Company, which isincorporated by reference as if fully set forth herein. For example,Dougan discloses a method involving the use of natural gas for conveyingkerogen-decomposing heat to the formation. The heated natural gas may beused as a solvent for thermally decomposed kerogen. The heated naturalgas exercises a solvent-stripping action with respect to the oil shaleby penetrating pores that exist in the shale. The natural gas carrierfluid, accompanied by decomposition product vapors and gases, passesupwardly through extraction wells into product recovery lines, and intoand through condensers interposed in such lines, where the decompositionvapors condense, leaving the natural gas carrier fluid to flow through aheater and into an injection well drilled into the deposit of oil shale.

[0024] Large deposits of heavy hydrocarbons (e.g., heavy oil and/or tar)contained within relatively permeable formations (e.g., in tar sands)are found in North America, South America, and Asia. Tar can besurface-mined and upgraded to lighter hydrocarbons such as crude oil,naphtha, kerosene, and/or gas oil. Tar sand deposits may, for example,first be mined. Surface milling processes may further separate thebitumen from sand. The separated bitumen may be converted to lighthydrocarbons using conventional refinery methods. Mining and upgradingtar sand is usually substantially more expensive than producing lighterhydrocarbons from conventional oil reservoirs.

[0025] U.S. Pat. No. 5,340,467 to Gregoli et al. and U.S. Pat. No.5,316,467 to Gregoli et al., which are incorporated by reference as iffully set forth herein, describe adding water and a chemical additive totar sand to form a slurry. The slurry may be separated into hydrocarbonsand water.

[0026] U.S. Pat. No. 4,409,090 to Hanson et al., which is incorporatedby reference as if fully set forth herein, describesphysically-separating tar sand into a bitumen-rich concentrate that mayhave some remaining sand. The bitumen-rich concentrate may be furtherseparated from sand in a fluidized bed.

[0027] U.S. Pat. No. 5,985,138 to Humphreys and U.S. Pat. No. 5,968,349to Duyvesteyn et al., which are incorporated by reference as if fullyset forth herein, describe mining tar sand and physically separatingbitumen from the tar sand. Further processing of bitumen in surfacefacilities may upgrade oil produced from bitumen.

[0028] In situ production of hydrocarbons from tar sand may beaccomplished by heating and/or injecting a gas into the formation. U.S.Pat. No. 5,211,230 to Ostapovich et al. and U.S. Pat. No. 5,339,897 toLeaute, which are incorporated by reference as if fully set forthherein, describe a horizontal production well located in an oil-bearingreservoir. A vertical conduit may be used to inject an oxidant gas intothe reservoir for in situ combustion.

[0029] U.S. Pat. No. 2,780,450 to Ljungstrom, which is incorporated byreference as if fully set forth herein, describes heating bituminousgeological formations in situ to convert or crack a liquid tar-likesubstance into oils and gases.

[0030] U.S. Pat. No. 4,597,441 to Ware et al, which is incorporated byreference as if fully set forth herein, describes contacting oil, heat,and hydrogen simultaneously in a reservoir. Hydrogenation may enhancerecovery of oil from the reservoir.

[0031] U.S. Pat. No. 5,046,559 to Glandt and 5,060,726 to Glandt et al,which are incorporated by reference as if fully set forth herein,describe preheating a portion of a tar sand formation between aninjector well and a producer well. Steam may be injected from theinjector well into the formation to produce hydrocarbons at the producerwell.

[0032] Substantial reserves of heavy hydrocarbons are known to exist informations that have relatively low permeability. For example, billionsof barrels of oil reserves are known to exist in diatomaceous formationsin California. Several methods have been proposed and/or used forproducing heavy hydrocarbons from relatively low permeabilityformations.

[0033] U.S. Pat. No. 5,415,231 to Northrop et al., which is incorporatedby reference as if fully set forth herein, describes a method forrecovering hydrocarbons (e.g. oil) from a low permeability subterraneanreservoir of the type comprised primarily of diatomite. A first slug orvolume of a heated fluid (e.g. 60% quality steam) is injected into thereservoir at a pressure greater than the fracturing pressure of thereservoir. The well is then shut in and the reservoir is allowed to soakfor a prescribed period (e.g. 10 days or more) to allow the oil to bedisplaced by the steam into the fractures. The well is then produceduntil the production rate drops below an economical level. A second slugof steam is then injected and the cycles are repeated.

[0034] U.S. Pat. No. 4,530,401 to Hartman et al., which is incorporatedby reference as if fully set forth herein, describes a method for therecovery of viscous oil from a subterranean, viscous oil-containingformation by injecting steam into the formation.

[0035] U.S. Pat. No. 5,339,897 to Leaute et al., which is incorporatedby reference as if fully set forth herein, describes a method andapparatus for recovering and/or upgrading hydrocarbons utilizing in situcombustion and horizontal wells.

[0036] U.S. Pat. No. 5,431,224 to Laali, which is incorporated byreference as if fully set forth herein, describes a method for improvinghydrocarbon flow from low permeability tight reservoir rock.

[0037] U.S. Pat. No. 5,297,626 Vinegar et al. and U.S. Pat. No.5,392,854 to Vinegar et al., which are incorporated by reference as iffully set forth herein, describe a process wherein an oil containingsubterranean formation is heated.

[0038] As outlined above, there has been a significant amount of effortto develop methods and systems to economically produce hydrocarbons,hydrogen, and/or other products from hydrocarbon containing formations.At present, however, there are still many hydrocarbon containingformations from which hydrocarbons, hydrogen, and/or other productscannot be economically produced. Thus, there is still a need forimproved methods and systems for production of hydrocarbons, hydrogen,and/or other products from various hydrocarbon containing formations.

SUMMARY OF THE INVENTION

[0039] In an embodiment, hydrocarbons within a hydrocarbon containingformation (e.g., a formation containing coal, oil shale, heavyhydrocarbons, or a combination thereof) may be converted in situ withinthe formation to yield a mixture of relatively high quality hydrocarbonproducts, hydrogen, and other products. One or more heat sources may beused to heat a portion of the hydrocarbon containing formation totemperatures that allow pyrolysis of the hydrocarbons. Hydrocarbons,hydrogen, and other formation fluids may be removed from the formationthrough one or more production wells. The formation fluids may beremoved in a vapor phase. Temperature and pressure in at least a portionof the formation may be controlled during pyrolysis to yield improvedproducts from the formation.

[0040] A heated formation may also be used to produce synthesis gas. Incertain embodiments synthesis gas is produced after production ofpyrolysis fluids.

[0041] A formation may be heated to a temperature greater than 400° C.prior to contacting a synthesis gas generating fluid with the formation.Contacting a synthesis gas generating fluid, such as water, steam,and/or carbon dioxide, with carbon and/or hydrocarbons within theformation results in generation of synthesis gas if the temperature ofthe carbon is sufficiently high. Synthesis gas generation is, in someembodiments, an endothermic process. Additional heat may be added to theformation during synthesis gas generation to maintain a high temperaturewithin the formation. The heat may be added from heater wells and/orfrom oxidizing carbon and/or hydrocarbons within the formation. Thegenerated synthesis gas may be removed from the formation through one ormore production wells.

[0042] After production of pyrolysis fluids and/or synthesis gas, fluidmay be sequestered within the formation. To store a significant amountof fluid within the formation, a temperature of the formation will oftenneed to be less than about 100° C. Water may be introduced into at leasta portion of the formation to generate steam and reduce a temperature ofthe formation. The steam may be removed from the formation. The steammay be utilized for various purposes, including, but not limited to,heating another portion of the formation, generating synthesis gas in anadjacent portion of the formation, generating electricity, and/or as asteam flood in a oil reservoir. After the formation is cooled, fluid(e.g., carbon dioxide) may be pressurized and sequestered in theformation. Sequestering fluid within the formation may result in asignificant reduction or elimination of fluid that is released to theenvironment due to operation of the in situ conversion process.

[0043] In an embodiment, one or more heat sources may be installed intoa formation to heat the formation. Heat sources may be installed bydrilling openings (well bores) into the formation. In some embodimentsopenings may be formed in the formation using a drill with a steerablemotor and an accelerometer. Alternatively, an opening may be formed intothe formation by geosteered drilling. Alternately, an opening may beformed into the formation by sonic drilling.

[0044] One or more heat sources may be disposed within the opening suchthat the heat source may be configured to transfer heat to theformation. For example, a heat source may be placed in an open wellborein the formation. In this manner, heat may conductively and radiativelytransfer from the heat source to the formation. Alternatively, a heatsource may be placed within a heater well that may be packed withgravel, sand, and/or cement. The cement may be a refractory cement.

[0045] In some embodiments one or more heat sources may be placed in apattern within the formation. For example, in one embodiment, an in situconversion process for hydrocarbons may include heating at least aportion of a hydrocarbon containing formation with an array of heatsources disposed within the formation. In some embodiments, the array ofheat sources can be positioned substantially equidistant from aproduction well. Certain patterns (e.g., triangular arrays, hexagonalarrays, or other array patterns) may be more desirable for specificapplications. In addition, the array of heat sources may be disposedsuch that a distance between each heat source may be less than about 70feet (21 m). In addition, the in situ conversion process forhydrocarbons may include heating at least a portion of the formationwith heat sources disposed substantially parallel to a boundary of thehydrocarbons. Regardless of the arrangement of or distance between theheat sources, in certain embodiments, a ratio of heat sources toproduction wells disposed within a formation may be greater than about5, 8, 10, 20, or more.

[0046] Certain embodiments may also include allowing heat to transferfrom one or more of the heat sources to a selected section of the heatedportion. In an embodiment, the selected section may be disposed betweenone or more heat sources. For example, the in situ conversion processmay also include allowing heat to transfer from one or more heat sourcesto a selected section of the formation such that heat from one or moreof the heat sources pyrolyzes at least some hydrocarbons within theselected section. In this manner, the in situ conversion process mayinclude heating at least a portion of a hydrocarbon containing formationabove a pyrolyzation temperature of hydrocarbons in the formation. Forexample, a pyrolyzation temperature may include a temperature of atleast about 270° C. Heat may be allowed to transfer from one or more ofthe heat sources to the selected section substantially by conduction.

[0047] One or more heat sources may be located within the formation suchthat superposition of heat produced from one or more heat sources mayoccur. Superposition of heat may increase a temperature of the selectedsection to a temperature sufficient for pyrolysis of at least some ofthe hydrocarbons within the selected section. Superposition of heat mayvary depending on, for example, a spacing between heat sources. Thespacing between heat sources may be selected to optimize heating of thesection selected for treatment. Therefore, hydrocarbons may be pyrolyzedwithin a larger area of the portion. In this manner, spacing betweenheat sources may be selected to increase the effectiveness of the heatsources, thereby increasing the economic viability of a selected in situconversion process for hydrocarbons. Superposition of heat tends toincrease the uniformity of heat distribution in the section of theformation selected for treatment.

[0048] Various systems and methods may be used to provide heat sources.In an embodiment, a natural distributed combustor system and method maybe configured to heat at least a portion of a hydrocarbon containingformation. The system and method may first include heating a firstportion of the formation to a temperature sufficient to supportoxidation of at least some of the hydrocarbons therein. One or moreconduits may be disposed within one or more openings. One or more of theconduits may be configured to provide an oxidizing fluid from anoxidizing fluid source into an opening in the formation. The oxidizingfluid may oxidize at least a portion of the hydrocarbons at a reactionzone within the formation. Oxidation may generate heat at the reactionzone. The generated heat may transfer from the reaction zone to apyrolysis zone in the formation. The heat may transfer by conduction,radiation, and/or convection. In this manner, a heated portion of theformation may include the reaction zone and the pyrolysis zone. Theheated portion may also be located substantially adjacent to theopening. One or more of the conduits may also be configured to removeone or more oxidation products from the reaction zone and/or formation.Alternatively, additional conduits may be configured to remove one ormore oxidation products from the reaction zone and/or formation.

[0049] In an embodiment, a system and method configured to heat ahydrocarbon containing formation may include one or more insulatedconductors disposed in one or more openings in the formation. Theopenings may be uncased. Alternatively, the openings may include acasing. As such, the insulated conductors may provide conductive,radiant, or convective heat to at least a portion of the formation. Inaddition, the system and method may be configured to allow heat totransfer from the insulated conductor to a section of the formation. Insome embodiments, the insulated conductor may include a copper-nickelalloy. In some embodiments, the insulated conductor may be electricallycoupled to two additional insulated conductors in a 3-phase Yconfiguration.

[0050] In an embodiment, a system and method may include one or moreelongated members disposed in an opening in the formation. Each of theelongated members may be configured to provide heat to at least aportion of the formation. One or more conduits may be disposed in theopening. One or more of the conduits may be configured to provide anoxidizing fluid from an oxidizing fluid source into the opening. Incertain embodiments, the oxidizing fluid may be configured tosubstantially inhibit carbon deposition on or proximate to the elongatedmember.

[0051] In an embodiment, a system and method for heating a hydrocarboncontaining formation may include oxidizing a fuel fluid in a heater. Themethod may further include providing at least a portion of the oxidizedfuel fluid into a conduit disposed in an opening in the formation. Inaddition, additional heat may be transferred from an electric heaterdisposed in the opening to the section of the formation. Heat may beallowed to transfer substantially uniformly along a length of theopening.

[0052] Energy input costs may be reduced in some embodiments of systemsand methods described above. For example, an energy input cost may bereduced by heating a portion of a hydrocarbon containing formation byoxidation in combination with heating the portion of the formation by anelectric heater. The electric heater may be turned down and/or off whenthe oxidation reaction begins to provide sufficient heat to theformation. In this manner, electrical energy costs associated withheating at least a portion of a formation with an electric heater may bereduced. Thus, a more economical process may be provided for heating ahydrocarbon containing formation in comparison to heating by aconventional method. In addition, the oxidation reaction may bepropagated slowly through a greater portion of the formation such thatfewer heat sources may be required to heat such a greater portion incomparison to heating by a conventional method.

[0053] Certain embodiments as described herein may provide a lower costsystem and method for heating a hydrocarbon containing formation. Forexample, certain embodiments may provide substantially uniform heattransfer along a length of a heater. Such a length of a heater may begreater than about 300 m or possibly greater than about 600 m. Inaddition, in certain embodiments, heat may be provided to the formationmore efficiently by radiation. Furthermore, certain embodiments ofsystems as described herein may have a substantially longer lifetimethan presently available systems.

[0054] In an embodiment, an in situ conversion system and method forhydrocarbons may include maintaining a portion of the formation in asubstantially unheated condition. In this manner, the portion mayprovide structural strength to the formation and/orconfinement/isolation to certain regions of the formation. A processedhydrocarbon containing formation may have alternating heated andsubstantially unheated portions arranged in a pattern that may, in someembodiments, resemble a checkerboard pattern, or a pattern ofalternating areas (e.g., strips) of heated and unheated portions.

[0055] In an embodiment, a heat source may advantageously heat onlyalong a selected portion or selected portions of a length of the heater.For example, a formation may include several hydrocarbon containinglayers. One or more of the hydrocarbon containing layers may beseparated by layers containing little or no hydrocarbons. A heat sourcemay include several discrete high heating zones that may be separated bylow heating zones. The high heating zones may be disposed proximatehydrocarbon containing layers such that the layers may be heated. Thelow heating zones may be disposed proximate to layers containing littleor no hydrocarbons such that the layers may not be substantially heated.For example, an electrical heater may include one or more low resistanceheater sections and one or more high resistance heater sections. In thismanner, low resistance heater sections of the electrical heater may bedisposed in and/or proximate to layers containing little or nohydrocarbons. In addition, high resistance heater sections of theelectrical heater may be disposed proximate hydrocarbon containinglayers. In an additional example, a fueled heater (e.g., surface burner)may include insulated sections. In this manner, insulated sections ofthe fueled heater may be placed proximate to or adjacent to layerscontaining little or no hydrocarbons. Alternately, a heater withdistributed air and/or fuel may be configured such that little or nofuel may be combusted proximate to or adjacent to layers containinglittle or no hydrocarbons. Such a fueled heater may include flamelesscombustors and natural distributed combustors.

[0056] In an embodiment, a heating rate of the formation may be slowlyraised through the pyrolysis temperature range. For example, an in situconversion process for hydrocarbons may include heating at least aportion of a hydrocarbon containing formation to raise an averagetemperature of the portion above about 270° C. by a rate less than aselected amount (e.g., about 10° C., 5° C., 3° C., 1° C., 0.5° C., or0.1° C.) per day. In a further embodiment, the portion may be heatedsuch that an average temperature of the selected section may be lessthan about 375° C. or, in some embodiments, less than about 400° C.

[0057] In an embodiment, a temperature of the portion may be monitoredthrough a test well disposed in a formation. For example, the test wellmay be positioned in a formation between a first heat source and asecond heat source. Certain systems and methods may include controllingthe heat from the first heat source and/or the second heat source toraise the monitored temperature at the test well at a rate of less thanabout a selected amount per day. In addition or alternatively, atemperature of the portion may be monitored at a production well. Inthis manner, an in situ conversion process for hydrocarbons may includecontrolling the heat from the first heat source and/or the second heatsource to raise the monitored temperature at the production well at arate of less than a selected amount per day.

[0058] Certain embodiments may include heating a selected volume of ahydrocarbon containing formation. Heat may be provided to the selectedvolume by providing power to one or more heat sources. Power may bedefined as heating energy per day provided to the selected volume. Apower (Pwr) required to generate a heating rate (h, in units of, forexample, ° C./day) in a selected volume (V) of a hydrocarbon containingformation may be determined by the following equation:Pwr=h*V*C_(v)*ρ_(B). In this equation, an average heat capacity of theformation (C_(v)) and an average bulk density of the formation (ρ_(B))may be estimated or determined using one or more samples taken from thehydrocarbon containing formation.

[0059] Certain embodiments may include raising and maintaining apressure in a hydrocarbon containing formation. Pressure may be, forexample, controlled within a range of about 2 bars absolute to about 20bars absolute. For example, the process may include controlling apressure within a majority of a selected section of a heated portion ofthe formation. The controlled pressure may be above about 2 barsabsolute during pyrolysis. In an alternate embodiment, an in situconversion process for hydrocarbons may include raising and maintainingthe pressure in the formation within a range of about 20 bars absoluteto about 36 bars absolute.

[0060] In an embodiment, compositions and properties of formation fluidsproduced by an in situ conversion process for hydrocarbons may varydepending on, for example, conditions within a hydrocarbon containingformation.

[0061] Certain embodiments may include controlling the heat provided toat least a portion of the formation such that production of lessdesirable products in the portion may be substantially inhibited.Controlling the heat provided to at least a portion of the formation mayalso increase the uniformity of permeability within the formation. Forexample, controlling the heating of the formation to inhibit productionof less desirable products may, in some embodiments, include controllingthe heating rate to less than a selected amount (e.g., 10° C., 5° C., 3°C., 1° C., 0.5° C., or 0.1° C.) per day.

[0062] Controlling pressure, heat and/or heating rates of a selectedsection in a formation may increase production of selected formationfluids. For example, the amount and/or rate of heating may be controlledto produce formation fluids having an American Petroleum Institute(“API”) gravity greater than about 25. Heat and/or pressure may becontrolled to inhibit production of olefins in the produced fluids.

[0063] Controlling formation conditions to control the pressure ofhydrogen in the produced fluid may result in improved qualities of theproduced fluids. In some embodiments it may be desirable to controlformation conditions so that the partial pressure of hydrogen in aproduced fluid is greater than about 0.5 bar absolute, as measured at aproduction well.

[0064] In an embodiment, operating conditions may be determined bymeasuring at least one property of the formation. At least the measuredproperties may be input into a computer executable program. At least oneproperty of formation fluids selected to be produced from the formationmay also be input into the computer executable program. The program maybe operable to determine a set of operating conditions from at least theone or more measured properties. The program may also be configured todetermine the set of operating conditions from at least one property ofthe selected formation fluids. In this manner, the determined set ofoperating conditions may be configured to increase production ofselected formation fluids from the formation.

[0065] Certain embodiments may include altering a composition offormation fluids produced from a hydrocarbon containing formation byaltering a location of a production well with respect to a heater well.For example, a production well may be located with respect to a heaterwell such that a non-condensable gas fraction of produced hydrocarbonfluids may be larger than a condensable gas fraction of the producedhydrocarbon fluids.

[0066] Condensable hydrocarbons produced from the formation willtypically include paraffins, cycloalkanes, mono-aromatics, anddi-aromatics as major components. Such condensable hydrocarbons may alsoinclude other components such as tri-aromatics, etc.

[0067] In certain embodiments, a majority of the hydrocarbons inproduced fluid may have a carbon number of less than approximately 25.Alternatively, less than about 15 weight % of the hydrocarbons in thefluid may have a carbon number greater than approximately 25. In otherembodiments fluid produced may have a weight ratio of hydrocarbonshaving carbon numbers from 2 through 4, to methane, of greater thanapproximately 1 (e.g., for oil shale and heavy hydrocarbons) or greaterthan approximately 0.3 (e.g., for coal). The non-condensablehydrocarbons may include, but is not limited to, hydrocarbons havingcarbon numbers less than 5.

[0068] In certain embodiments, the API gravity of the hydrocarbons inproduced fluid may be approximately 25 or above (e.g., 30, 40, 50,etc.). In certain embodiments, the hydrogen to carbon atomic ratio inproduced fluid may be at least approximately 1.7 (e.g., 1.8, 1.9, etc.).

[0069] In certain embodiments, (e.g., when the formation includes coal)fluid produced from a formation may include oxygenated hydrocarbons. Inan example, the condensable hydrocarbons may include an amount ofoxygenated hydrocarbons greater than about 5% by weight of thecondensable hydrocarbons.

[0070] Condensable hydrocarbons of a produced fluid may also includeolefins. For example, the olefin content of the condensable hydrocarbonsmay be from about 0.1% by weight to about 15% by weight. Alternatively,the olefin content of the condensable hydrocarbons may be from about0.1% by weight to about 2.5% by weight or, in some embodiments less thanabout 5% by weight.

[0071] Non-condensable hydrocarbons of a produced fluid may also includeolefins. For example, the olefin content of the non-condensablehydrocarbons may be gauged using the ethene/ethane molar ratio. Incertain embodiments the ethene/ethane molar ratio may range from about0.001 to about 0.15.

[0072] Fluid produced from the formation may include aromatic compounds.For example, the condensable hydrocarbons may include an amount ofaromatic compounds greater than about 20% or about 25% by weight of thecondensable hydrocarbons. The condensable hydrocarbons may also includerelatively low amounts of compounds with more than two rings in them(e.g., tri-aromatics or above). For example, the condensablehydrocarbons may include less than about 1%, 2%, or about 5% by weightof tri-aromatics or above in the condensable hydrocarbons.

[0073] In particular, in certain embodiments asphaltenes (i.e., largemulti-ring aromatics that are substantially insoluble in hydrocarbons)make up less than about 0.1% by weight of the condensable hydrocarbons.For example, the condensable hydrocarbons may include an asphaltenecomponent of from about 0.0% by weight to about 0.1% by weight or, insome embodiments, less than about 0.3% by weight.

[0074] Condensable hydrocarbons of a produced fluid may also includerelatively large amounts of cycloalkanes. For example, the condensablehydrocarbons may include a cycloalkane component of up to 30% by weight(e.g., from about 5% by weight to about 30 % by weight) of thecondensable hydrocarbons.

[0075] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing nitrogen. Forexample, less than about 1% by weight (when calculated on an elementalbasis) of the condensable hydrocarbons is nitrogen (e.g., typically thenitrogen is in nitrogen containing compounds such as pyridines, amines,amides, etc.).

[0076] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing oxygen. Forexample, in certain embodiments (e.g., for oil shale and heavyhydrocarbons) less than about 1% by weight (when calculated on anelemental basis) of the condensable hydrocarbons is oxygen (e.g.,typically the oxygen is in oxygen containing compounds such as phenols,substituted phenols, ketones, etc.). In certain other embodiments (e.g.,for coal) between about 5% and about 30% by weight of the condensablehydrocarbons are typically oxygen containing compounds such as phenols,substituted phenols, ketones, etc. In some instances certain compoundscontaining oxygen (e.g., phenols) may be valuable and, as such, may beeconomically separated from the produced fluid.

[0077] In certain embodiments, the condensable hydrocarbons of the fluidproduced from a formation may include compounds containing sulfur. Forexample, less than about 1% by weight (when calculated on an elementalbasis) of the condensable hydrocarbons is sulfur (e.g., typically thesulfur is in sulfur containing compounds such as thiophenes, mercaptans,etc.).

[0078] Furthermore, the fluid produced from the formation may includeammonia (typically the ammonia condenses with the water, if any,produced from the formation). For example, the fluid produced from theformation may in certain embodiments include about 0.05% or more byweight of ammonia. Certain formations may produce larger amounts ofammonia (e.g., up to about 10% by weight of the total fluid produced maybe ammonia).

[0079] Furthermore, a produced fluid from the formation may also includemolecular hydrogen (H₂), water, carbon dioxide, hydrogen sulfide, etc.For example, the fluid may include a H₂ content between about 10% toabout 80% by volume of the non-condensable hydrocarbons.

[0080] Certain embodiments may include heating to yield at least about15% by weight of a total organic carbon content of at least some of thehydrocarbon containing formation into formation fluids.

[0081] In an embodiment, an in situ conversion process for treating ahydrocarbon containing formation may include providing heat to a sectionof the formation to yield greater than about 60% by weight of thepotential hydrocarbon products and hydrogen, as measured by the FischerAssay.

[0082] In certain embodiments, heating of the selected section of theformation may be controlled to pyrolyze at least about 20% by weight (orin some embodiments about 25% by weight) of the hydrocarbons within theselected section of the formation.

[0083] Certain embodiments may include providing a reducing agent to atleast a portion of the formation. A reducing agent provided to a portionof the formation during heating may increase production of selectedformation fluids. A reducing agent may include, but is not limited to,molecular hydrogen. For example, pyrolyzing at least some hydrocarbonsin a hydrocarbon containing formation may include forming hydrocarbonfragments. Such hydrocarbon fragments may react with each other andother compounds present in the formation. Reaction of these hydrocarbonfragments may increase production of olefin and aromatic compounds fromthe formation. Therefore, a reducing agent provided to the formation mayreact with hydrocarbon fragments to form selected products and/orinhibit the production of non-selected products.

[0084] In an embodiment, a hydrogenation reaction between a reducingagent provided to a hydrocarbon containing formation and at least someof the hydrocarbons within the formation may generate heat. Thegenerated heat may be allowed to transfer such that at least a portionof the formation may be heated. A reducing agent such as molecularhydrogen may also be autogenously generated within a portion of ahydrocarbon containing formation during an in situ conversion processfor hydrocarbons. In this manner, the autogenously generated molecularhydrogen may hydrogenate formation fluids within the formation. Allowingformation waters to contact hot carbon in the spent formation maygenerate molecular hydrogen. Cracking an injected hydrocarbon fluid mayalso generate molecular hydrogen.

[0085] Certain embodiments may also include providing a fluid producedin a first portion of a hydrocarbon containing formation to a secondportion of the formation. In this manner, a fluid produced in a firstportion of a hydrocarbon containing formation may be used to produce areducing environment in a second portion of the formation. For example,molecular hydrogen generated in a first portion of a formation may beprovided to a second portion of the formation. Alternatively, at least aportion of formation fluids produced from a first portion of theformation may be provided to a second portion of the formation toprovide a reducing environment within the second portion. The secondportion of the formation may be treated according to any of theembodiments described herein.

[0086] Certain embodiments may include controlling heat provided to atleast a portion of the formation such that a thermal conductivity of theportion may be increased to greater than about 0.5 W/(m ° C.) or, insome embodiments, greater than about 0.6 W/(m ° C.).

[0087] In certain embodiments a mass of at least a portion of theformation may be reduced due, for example, to the production offormation fluids from the formation. As such, a permeability andporosity of at least a portion of the formation may increase. Inaddition, removing water during the heating may also increase thepermeability and porosity of at least a portion of the formation.

[0088] Certain embodiments may include increasing a permeability of atleast a portion of a hydrocarbon containing formation to greater thanabout 0.01, 0.1, 1, 10, 20 and/or 50 Darcy. In addition, certainembodiments may include substantially uniformly increasing apermeability of at least a portion of a hydrocarbon containingformation. Some embodiments may include increasing a porosity of atleast a portion of a hydrocarbon containing formation substantiallyuniformly.

[0089] In certain embodiments, after pyrolysis of a portion of aformation, synthesis gas may be produced from carbon and/or hydrocarbonsremaining within the formation. Pyrolysis of the portion may produce arelatively high, substantially uniform permeability throughout theportion. Such a relatively high, substantially uniform permeability mayallow generation of synthesis gas from a significant portion of theformation at relatively low pressures. The portion may also have a largesurface area and/or surface area/volume. The large surface area mayallow synthesis gas producing reactions to be substantially atequilibrium conditions during synthesis gas generation. The relativelyhigh, substantially uniform permeability may result in a relatively highrecovery efficiency of synthesis gas, as compared to synthesis gasgeneration in a hydrocarbon containing formation that has not been sotreated.

[0090] Synthesis gas may be produced from the formation prior to orsubsequent to producing a formation fluid from the formation. Forexample, synthesis gas generation may be commenced before and/or afterformation fluid production decreases to an uneconomical level. In thismanner, heat provided to pyrolyze hydrocarbons within the formation mayalso be used to generate synthesis gas. For example, if a portion of theformation is at a temperature from approximately 270° C. toapproximately 375° C. (or 400° C. in some embodiments) afterpyrolyzation, then less additional heat is generally required to heatsuch portion to a temperature sufficient to support synthesis gasgeneration.

[0091] Pyrolysis of at least some hydrocarbons may in some embodimentsconvert about 15% by weight or more of the carbon initially available.Synthesis gas generation may convert approximately up to an additional80% by weight or more of carbon initially available within the portion.In this manner, in situ production of synthesis gas from a hydrocarboncontaining formation may allow conversion of larger amounts of carboninitially available within the portion. The amount of conversionachieved may, in some embodiments, be limited by subsidence concerns.

[0092] Certain embodiments may include providing heat from one or moreheat sources to heat the formation to a temperature sufficient to allowsynthesis gas generation (e.g., in a range of approximately 400° C. toapproximately 1200° C. or higher). At a lower end of the temperaturerange, generated synthesis gas may have a high hydrogen (H₂) to carbonmonoxide (CO) ratio. At an upper end of the temperature range, generatedsynthesis gas may include mostly H₂ and CO in lower ratios (e.g.,approximately a 1:1 ratio).

[0093] Heat sources for synthesis gas production may include any of theheat sources as described in any of the embodiments set forth herein.Alternatively, heating may include transferring heat from a heattransfer fluid (e.g., steam or combustion products from a burner)flowing within a plurality of wellbores within the formation.

[0094] A synthesis gas generating fluid (e.g., liquid water, steam,carbon dioxide, air, oxygen, hydrocarbons, and mixtures thereof) may beprovided to the formation. For example, the synthesis gas generatingfluid mixture may include steam and oxygen. In an embodiment, asynthesis gas generating fluid may include aqueous fluid produced bypyrolysis of at least some hydrocarbons within one or more otherportions of the formation. Providing the synthesis gas generating fluidmay alternatively include raising a water table of the formation toallow water to flow into it. Synthesis gas generating fluid may also beprovided through at least one injection wellbore. The synthesis gasgenerating fluid will generally react with carbon in the formation toform H₂, water, methane, CO₂, and/or CO. A portion of the carbon dioxidemay react with carbon in the formation to generate carbon monoxide.Hydrocarbons such as ethane may be added to a synthesis gas generatingfluid. When introduced into the formation, the hydrocarbons may crack toform hydrogen and/or methane. The presence of methane in producedsynthesis gas may increase the heating value of the produced synthesisgas.

[0095] Synthesis gas generating reactions are typically endothermicreactions. In an embodiment, an oxidant may be added to a synthesis gasgenerating fluid. The oxidant may include, but is not limited to, air,oxygen enriched air, oxygen, hydrogen peroxide, other oxidizing fluids,or combinations thereof. The oxidant may react with carbon within theformation to exothermically generate heat. Reaction of an oxidant withcarbon in the formation may result in production of CO₂ and/or CO.Introduction of an oxidant to react with carbon in the formation mayeconomically allow raising the formation temperature high enough toresult in generation of significant quantities of H₂ and CO fromhydrocarbons within the formation. Synthesis gas generation may be via abatch process or a continuous process, as is further described herein.

[0096] Synthesis gas may be produced from one or more producer wellsthat include one or more heat sources. Such heat sources may operate topromote production of the synthesis gas with a desired composition.

[0097] Certain embodiments may include monitoring a composition of theproduced synthesis gas, and then controlling heating and/or controllinginput of the synthesis gas generating fluid to maintain the compositionof the produced synthesis gas within a desired range. For example, insome embodiments (e.g., such as when the synthesis gas will be used as afeedstock for a Fischer-Tropsch process) a desired composition of theproduced synthesis gas may have a ratio of hydrogen to carbon monoxideof about 1.8:1 to 2.2:1 (e.g., about 2:1 or about 2.1:1). In someembodiments (such as when the synthesis gas will be used as a feedstockto make methanol) such ratio may be about 3:1 (e.g., about 2.8:1 to3.2:1).

[0098] Certain embodiments may include blending a first synthesis gaswith a second synthesis gas to produce synthesis gas of a desiredcomposition. The first and the second synthesis gases may be producedfrom different portions of the formation.

[0099] Synthesis gases described herein may be converted to heaviercondensable hydrocarbons. For example, a Fischer-Tropsch hydrocarbonsynthesis process may be configured to convert synthesis gas to branchedand unbranched paraffins. Paraffins produced from the Fischer-Tropschprocess may be used to produce other products such as diesel, jet fuel,and naphtha products. The produced synthesis gas may also be used in acatalytic methanation process to produce methane. Alternatively, theproduced synthesis gas may be used for production of methanol, gasolineand diesel fuel, ammonia, and middle distillates. Produced synthesis gasmay be used to heat the formation as a combustion fuel. Hydrogen inproduced synthesis gas may be used to upgrade oil.

[0100] Synthesis gas may also be used for other purposes. Synthesis gasmay be combusted as fuel. Synthesis gas may also be used forsynthesizing a wide range of organic and/or inorganic compounds such ashydrocarbons and ammonia. Synthesis gas may be used to generateelectricity, by combusting it as a fuel, by reducing the pressure of thesynthesis gas in turbines, and/or using the temperature of the synthesisgas to make steam (and then run turbines). Synthesis gas may also beused in an energy generation unit such as a molten carbonate fuel cell,a solid oxide fuel cell, or other type of fuel cell.

[0101] Certain embodiments may include separating a fuel cell feedstream from fluids produced from pyrolysis of at least some of thehydrocarbons within a formation. The fuel cell feed stream may includeH₂, hydrocarbons, and/or carbon monoxide. In addition, certainembodiments may include directing the fuel cell feed stream to a fuelcell to produce electricity. The electricity generated from thesynthesis gas or the pyrolyzation fluids in the fuel cell may beconfigured to power electrical heaters, which may be configured to heatat least a portion of the formation. Certain embodiments may includeseparating carbon dioxide from a fluid exiting the fuel cell. Carbondioxide produced from a fuel cell or a formation may be used for avariety of purposes.

[0102] In an embodiment, a portion of a formation that has beenpyrolyzed and/or subjected to synthesis gas generation may be allowed tocool or may be cooled to form a cooled, spent portion within theformation. For example, a heated portion of a formation may be allowedto cool by transference of heat to adjacent portion of the formation.The transference of heat may occur naturally or may be forced by theintroduction of heat transfer fluids through the heated portion and intoa cooler portion of the formation. Alternatively, introducing water tothe first portion of the formation may cool the first portion. Waterintroduced into the first portion may be removed from the formation assteam. The removed steam or hot water may be injected into a hot portionof the formation to create synthesis gas.

[0103] Cooling the formation may provide certain benefits such asincreasing the strength of the rock in the formation (thereby mitigatingsubsidence), increasing absorptive capacity of the formation, etc.

[0104] In an embodiment, a cooled, spent portion of a hydrocarboncontaining formation may be used to store and/or sequester othermaterials such as carbon dioxide. Carbon dioxide may be injected underpressure into the cooled, spent portion of the formation. The injectedcarbon dioxide may adsorb onto hydrocarbons in the formation and/orreside in void spaces such as pores in the formation. The carbon dioxidemay be generated during pyrolysis, synthesis gas generation, and/orextraction of useful energy.

[0105] In an embodiment, produced formation fluids may be stored in acooled, spent portion of the formation. In some embodiments carbondioxide may be stored in relatively deep coal beds, and used to desorbcoal bed methane.

[0106] Many of the in situ processes and/or systems described herein maybe used to produce hydrocarbons, hydrogen and other formation fluidsfrom a relatively permeable formation that includes heavy hydrocarbons(e.g., from tar sands). Heating may be used to mobilize the heavyhydrocarbons within the formation, and then to pyrolyze heavyhydrocarbons within the formation to form pyrolyzation fluids. Formationfluids produced during pyrolyzation may be removed from the formationthrough production wells.

[0107] In certain embodiments fluid (e.g., gas) may be provided to arelatively permeable formation. The gas may be used to pressurize theformation. A pressure in the formation may be selected to controlmobilization of fluid within the formation. For example, a higherpressure may increase the mobilization of fluid within the formationsuch that fluids may be produced at a higher rate.

[0108] In an embodiment, a portion of a relatively permeable formationmay be heated to reduce a viscosity of the heavy hydrocarbons within theformation. The reduced viscosity heavy hydrocarbons may be mobilized.The mobilized heavy hydrocarbons may flow to a selected pyrolyzationsection of the formation. A gas may be provided into the relativelypermeable formation to increase a flow of the mobilized heavyhydrocarbons into the selected pyrolyzation section. Such a gas may be,for example, carbon dioxide (the carbon dioxide may be stored in theformation after removal of the heavy hydrocarbons). The heavyhydrocarbons within the selected pyrolyzation section may besubstantially pyrolyzed. Pyrolyzation of the mobilized heavyhydrocarbons may upgrade the heavy hydrocarbons to a more desirableproduct. The pyrolyzed heavy hydrocarbons may be removed from theformation through a production well. In some embodiments, the mobilizedheavy hydrocarbons may be removed from the formation through aproduction well without upgrading or pyrolyzing the heavy hydrocarbons.

[0109] Hydrocarbon fluids produced from the formation may vary dependingon conditions within the formation. For example, a heating rate of aselected pyrolyzation section may be controlled to increase theproduction of selected products. In addition, pressure within theformation may be controlled to vary the composition of the producedfluids.

[0110] Certain systems and methods described herein may be used to treatheavy hydrocarbons in at least a portion of a relatively lowpermeability formation (e.g., in “tight” formations that contain heavyhydrocarbons). Such heavy hydrocarbons may be heated to pyrolyze atleast some of the heavy hydrocarbons in a selected section of theformation. Heating may also increase the permeability of at least aportion of the selected section. Fluids generated from pyrolysis may beproduced from the formation.

[0111] Certain embodiments for treating heavy hydrocarbons in arelatively low permeability formation may include providing heat fromone or more heat sources to pyrolyze some of the heavy hydrocarbons andthen to vaporize a portion of the heavy hydrocarbons. The heat sourcesmay pyrolyze at least some heavy hydrocarbons in a selected section ofthe formation and may pressurize at least a portion of the selectedsection. During the heating, the pressure within the formation mayincrease substantially. The pressure in the formation may be controlledsuch that the pressure in the formation may be maintained to produce afluid of a desired composition. Pyrolyzation fluid may be removed fromthe formation as vapor from one or more heater wells by using the backpressure created by heating the formation.

[0112] Certain embodiments for treating heavy hydrocarbons in at least aportion of a relatively low permeability formation may include heatingto create a pyrolysis zone and heating a selected second section to lessthan the average temperature within the pyrolysis zone. Heavyhydrocarbons may be pyrolyzed in the pyrolysis zone. Heating theselected second section may decrease the viscosity of some of the heavyhydrocarbons in the selected second section to create a low viscosityzone. The decrease in viscosity of the fluid in the selected secondsection may be sufficient such that at least some heated heavyhydrocarbons within the selected second section may flow into thepyrolysis zone. Pyrolyzation fluid may be produced from the pyrolysiszone. In one embodiment, the density of the heat sources in thepyrolysis zone may be greater than in the low viscosity zone.

[0113] In certain embodiments it may be desirable to create thepyrolysis zones and low viscosity zones sequentially over time. The heatsources in a region near a desired pyrolysis zone may be activatedfirst, resulting in a substantially uniform pyrolysis zone that may beestablished after a period of time. Once the pyrolysis zone isestablished, heat sources in the low viscosity zone may be activatedsequentially from nearest to farthest from the pyrolysis zone.

BRIEF DESCRIPTION OF THE DRAWINGS

[0114] Further advantages of the present invention may become apparentto those skilled in the art with the benefit of the following detaileddescription of the preferred embodiments and upon reference to theaccompanying drawings in which:

[0115]FIG. 1 depicts an illustration of stages of heating a hydrocarboncontaining formation;

[0116]FIG. 2 depicts a diagram of properties of a hydrocarbon containingformation;

[0117]FIG. 3 depicts an embodiment of a heat source pattern;

[0118]FIGS. 3a-3 c depict embodiments of heat sources;

[0119]FIG. 4 depicts an embodiment of heater wells located in ahydrocarbon containing formation;

[0120]FIG. 5 depicts an embodiment of a pattern of heater wells in ahydrocarbon containing formation;

[0121]FIG. 6 depicts an embodiment of a heated portion of a hydrocarboncontaining formation;

[0122]FIG. 7 depicts an embodiment of superposition of heat in ahydrocarbon containing formation;

[0123]FIG. 8 and FIG. 9 depict embodiments of a pattern of heat sourcesand production wells in a hydrocarbon containing formation;

[0124]FIG. 10 depicts an embodiment of a natural distributed combustorheat source;

[0125]FIG. 11 depicts a portion of an overburden of a formation with aheat source;

[0126]FIG. 12 and FIG. 13 depict embodiments of a natural distributedcombustor heater;

[0127]FIG. 14 and FIG. 15 depict embodiments of a system for heating aformation;

[0128] FIGS. 16-21 depict several embodiments of an insulated conductorheat source;

[0129]FIG. 22 and FIGS. 23a-23 b depict several embodiments of acentralizer;

[0130]FIG. 24 depicts an embodiment of a conductor-in-conduit heatsource in a formation;

[0131]FIG. 25 depicts an embodiment of a heat source in a formation;

[0132]FIG. 26 depicts an embodiment of a surface combustor heat source;

[0133]FIG. 27 depicts an embodiment of a conduit for a heat source ;

[0134]FIG. 28 depicts an embodiment of a flameless combustor heatsource;

[0135]FIG. 29 depicts an embodiment of using pyrolysis water to generatesynthesis gas in a formation;

[0136]FIG. 30 depicts an embodiment of synthesis gas production in aformation;

[0137]FIG. 31 depicts an embodiment of continuous synthesis gasproduction in a formation;

[0138]FIG. 32 depicts an embodiment of batch synthesis gas production ina formation;

[0139]FIG. 33 depicts an embodiment of producing energy with synthesisgas produced from a hydrocarbon containing formation;

[0140]FIG. 34 depicts an embodiment of producing energy withpyrolyzation fluid produced from a hydrocarbon containing formation;

[0141]FIG. 35 depicts an embodiment of synthesis gas production from aformation;

[0142]FIG. 36 depicts an embodiment of sequestration of carbon dioxideproduced during pyrolysis in a hydrocarbon containing formation;

[0143]FIG. 37 depicts an embodiment of producing energy with synthesisgas produced from a hydrocarbon containing formation;

[0144]FIG. 38 depicts an embodiment of a Fischer-Tropsch process usingsynthesis gas produced from a hydrocarbon containing formation;

[0145]FIG. 39 depicts an embodiment of a Shell Middle Distillatesprocess using synthesis gas produced from a hydrocarbon containingformation;

[0146]FIG. 40 depicts an embodiment of a catalytic methanation processusing synthesis gas produced from a hydrocarbon containing formation;

[0147]FIG. 41 depicts an embodiment of production of ammonia and ureausing synthesis gas produced from a hydrocarbon containing formation;

[0148]FIG. 42 depicts an embodiment of production of ammonia usingsynthesis gas produced from a hydrocarbon containing formation;

[0149]FIG. 43 depicts an embodiment of preparation of a feed stream foran ammonia process;

[0150] FIGS. 44-48 depict several embodiments for treating a relativelypermeable formation;

[0151]FIG. 49 and FIG. 50 depict embodiments of heat sources in arelatively permeable formation;

[0152] FIGS. 51-57 depict several embodiments of heat sources in arelatively low permeability formation;

[0153] FIGS. 58-70 depict several embodiments of a heat source andproduction well pattern;

[0154]FIG. 71 depicts an embodiment of surface facilities for treating aformation fluid;

[0155]FIG. 72 depicts an embodiment of a catalytic flameless distributedcombustor;

[0156]FIG. 73 depicts an embodiment of surface facilities for treating aformation fluid;

[0157]FIG. 74 depicts an embodiment of a square pattern of heat sourcesand production wells;

[0158]FIG. 75 depicts an embodiment of a heat source and production wellpattern;

[0159]FIG. 76 depicts an embodiment of a triangular pattern of heatsources;

[0160]FIG. 76a depicts an embodiment of a square pattern of heatsources;

[0161]FIG. 77 depicts an embodiment of a hexagonal pattern of heatsources;

[0162]FIG. 77a depicts an embodiment of a 12 to 1 pattern of heatsources;

[0163]FIG. 78 depicts a temperature profile for a triangular pattern ofheat sources;

[0164]FIG. 79 depicts a temperature profile for a square pattern of heatsources;

[0165]FIG. 79a depicts a temperature profile for a hexagonal pattern ofheat sources;

[0166]FIG. 80 depicts a comparison plot between the average patterntemperature and temperatures at the coldest spots for various patternsof heat sources;

[0167]FIG. 81 depicts a comparison plot between the average patterntemperature and temperatures at various spots within triangular andhexagonal pattern of heat sources;

[0168]FIG. 81a depicts a comparison plot between the average patterntemperature and temperatures at various spots within a square pattern ofheat sources;

[0169]FIG. 81b depicts a comparison plot between temperatures at thecoldest spots of various pattern of heat sources;

[0170]FIG. 82 depicts extension of a reaction zone in a heated formationover time;

[0171]FIG. 83 and FIG. 84 depict the ratio of conductive heat transferto radiative heat transfer in a formation;

[0172] FIGS. 85-88 depict temperatures of a conductor, a conduit, and anopening in a formation versus a temperature at the face of a formation;

[0173]FIG. 89 depicts a retort and collection system;

[0174]FIG. 90 depicts pressure versus temperature in an oil shalecontaining formation during pyrolysis;

[0175]FIG. 91 depicts quality of oil produced from an oil shalecontaining formation;

[0176]FIG. 92 depicts ethene to ethane ratio produced from an oil shalecontaining formation as a function of temperature and pressure;

[0177]FIG. 93 depicts yield of fluids produced from an oil shalecontaining formation as a function of temperature and pressure;

[0178]FIG. 94 depicts a plot of oil yield produced from treating an oilshale containing formation;

[0179]FIG. 95 depicts yield of oil produced from treating an oil shalecontaining formation;

[0180]FIG. 96 depicts hydrogen to carbon ratio of hydrocarbon condensateproduced from an oil shale containing formation as a function oftemperature and pressure;

[0181]FIG. 97 depicts olefin to paraffin ratio of hydrocarbon condensateproduced from an oil shale containing formation as a function ofpressure and temperature;

[0182]FIG. 98 depicts relationships between properties of a hydrocarbonfluid produced from an oil shale containing formation;

[0183]FIG. 99 depicts quantity of oil produced from an oil shalecontaining formation as a function of partial pressure of H₂;

[0184]FIG. 100 depicts ethene to ethane ratios of fluid produced from anoil shale containing formation as a function of temperature andpressure;

[0185]FIG. 101 depicts hydrogen to carbon atomic ratios of fluidproduced from an oil shale containing formation as a function oftemperature and pressure;

[0186]FIG. 102 depicts an embodiment of an apparatus for a drumexperiment;

[0187]FIG. 103 depicts a plot of ethene to ethane ratio versus hydrogenconcentration;

[0188]FIG. 104 depicts a heat source and production well pattern for afield experiment in an oil shale containing formation;

[0189]FIG. 105 depicts a cross-sectional view of the field experiment;

[0190]FIG. 106 depicts a plot of temperature within the oil shalecontaining formation during the field experiment;

[0191]FIG. 107 depicts pressure within the oil shale containingformation during the field experiment;

[0192]FIG. 108 depicts a plot of API gravity of a fluid produced fromthe oil shale containing formation during the field experiment versustime;

[0193]FIG. 109 depicts average carbon numbers of fluid produced from theoil shale containing formation during the field experiment versus time;

[0194]FIG. 110 depicts density of fluid produced from the oil shalecontaining formation during the field experiment versus time;

[0195]FIG. 111 depicts a plot of weight percent of hydrocarbons withinfluid produced from the oil shale containing formation during the fieldexperiment;

[0196]FIG. 112 depicts a plot of an average yield of oil from the oilshale containing formation during the field experiment;

[0197]FIG. 113 depicts experimental data from laboratory experiments onoil shale;

[0198]FIG. 114 depicts total hydrocarbon production and liquid phasefraction versus time of a fluid produced from an oil shale containingformation;

[0199]FIG. 115 depicts weight percent of paraffins versus vitrinitereflectance;

[0200]FIG. 116 depicts weight percent of cycloalkanes in produced oilversus vitrinite reflectance;

[0201]FIG. 117 depicts weight percentages of paraffins and cycloalkanesin produced oil versus vitrinite reflectance;

[0202]FIG. 118 depicts phenol weight percent in produced oil versusvitrinite reflectance;

[0203]FIG. 119 depicts aromatic weight percent in produced oil versusvitrinite reflectance;

[0204]FIG. 120 depicts ratio of paraffins and aliphatics to aromaticsversus vitrinite reflectance;

[0205]FIG. 121 depicts yields of paraffins versus vitrinite reflectance;

[0206]FIG. 122 depicts yields of cycloalkanes versus vitrinitereflectance;

[0207]FIG. 123 depicts yields of cycloalkanes and paraffins versusvitrinite reflectance;

[0208]FIG. 124 depicts yields of phenol versus vitrinite reflectance;

[0209]FIG. 125 depicts API gravity as a function of vitrinitereflectance;

[0210]FIG. 126 depicts yield of oil from a coal containing formation asa function of vitrinite reflectance;

[0211]FIG. 127 depicts CO₂ yield from coal having various vitrinitereflectances;

[0212]FIG. 128 depicts CO₂ yield versus atomic O/C ratio for a coalcontaining formation;

[0213]FIG. 129 depicts a schematic of a coal cube experiment;

[0214]FIG. 130 depicts in situ temperature profiles for electricalresistance heaters, and natural distributed combustion heaters;

[0215]FIG. 131 depicts equilibrium gas phase compositions produced fromexperiments on a coal cube;

[0216]FIG. 132 depicts cumulative production of gas as a function oftemperature produced by heating a coal cube;

[0217]FIG. 133 depicts cumulative condensable hydrocarbons and water asa function of temperature produced by heating a coal cube;

[0218]FIG. 134 depicts the compositions of condensable hydrocarbonsproduced when various ranks of coal were treated;

[0219]FIG. 135 depicts thermal conductivity of coal versus temperature;

[0220]FIG. 136 depicts a cross-sectional view of an in situ experimentalfield test;

[0221]FIG. 137 depicts locations of heat sources and wells in anexperimental field test;

[0222]FIG. 138 and FIG. 139 depict temperature versus time in anexperimental field test;

[0223]FIG. 140 depicts volume of oil produced from an experimental fieldtest as a function of time;

[0224]FIG. 141 depicts carbon number distribution of fluids producedfrom an experimental field test;

[0225]FIG. 142 depicts weight percent of a hydrocarbon produced from twolaboratory experiments on coal from the 1 field test site versus carbonnumber distribution;

[0226]FIG. 143 depicts fractions from separation of coal oils treated byFischer assay and treated by slow heating in a coal cube experiment;

[0227]FIG. 144 depicts percentage ethene to ethane produced from a coalcontaining formation as a function of heating rate in an experimentalfield test;

[0228]FIG. 145 depicts product quality of fluids produced from a coalcontaining formation as a function of heating rate in an experimentalfield test;

[0229]FIG. 146 depicts weight percentages of various fluids producedfrom a coal containing formation for various heating rates in anexperimental field test;

[0230]FIG. 147 depicts CO₂ produced at three different locations versustime in an experimental field test;

[0231]FIG. 148 depicts volatiles produced from a coal containingformation in an experimental field test versus cumulative energycontent;

[0232]FIG. 149 depicts volume of gas produced from a coal containingformation in an experimental field test as a function of time;

[0233]FIG. 150 depicts volume of oil produced from a coal containingformation in an experimental field test as a function of energy input;

[0234]FIG. 151 depicts synthesis gas production from the coal containingformation in an experimental field test versus the total water inflow;

[0235]FIG. 152 depicts additional synthesis gas production from the coalcontaining formation in an experimental field test due to injectedsteam;

[0236]FIG. 153 depicts the effect of methane injection into a heatedformation;

[0237]FIG. 154 depicts the effect of ethane injection into a heatedformation;

[0238]FIG. 155 depicts the effect of propane injection into a heatedformation;

[0239]FIG. 156 depicts the effect of butane injection into a heatedformation;

[0240]FIG. 157 depicts composition of gas produced from a formationversus time;

[0241]FIG. 158 depicts synthesis gas conversion versus time;

[0242]FIG. 159 depicts calculated equilibrium gas dry mole fractions fora reaction of coal with water;

[0243]FIG. 160 depicts calculated equilibrium gas wet mole fractions fora reaction of coal with water;

[0244]FIG. 161 depicts an example of pyrolysis and synthesis gasproduction stages in a coal containing formation;

[0245]FIG. 162 depicts an example of low temperature in situ synthesisgas production;

[0246]FIG. 163 depicts an example of high temperature in situ synthesisgas production;

[0247]FIG. 164 depicts an example of in situ synthesis gas production ina hydrocarbon containing formation;

[0248]FIG. 165 depicts a plot of cumulative adsorbed methane and carbondioxide versus pressure in a coal containing formation;

[0249]FIG. 166 depicts an embodiment of in situ synthesis gas productionintegrated with a Fischer-Tropsch process;

[0250]FIG. 167 depicts a comparison between numerical simulation dataand experimental field test data of synthesis gas composition producedas a function of time;

[0251]FIG. 168 depicts weight percentages of carbon compounds versuscarbon number produced from a heavy hydrocarbon containing formation;

[0252]FIG. 169 depicts weight percentages of carbon compounds producedfrom a heavy hydrocarbon containing formation versus heating rate andpressure;

[0253]FIG. 170 depicts a plot of oil production versus time in a heavyhydrocarbon containing formation;

[0254]FIG. 171 depicts ratio of heat content of fluids produced from aheavy hydrocarbon containing formation to heat input versus time;

[0255]FIG. 172 depicts numerical simulation data of weight percentageversus carbon number distribution produced from a heavy hydrocarboncontaining formation;

[0256]FIG. 173 depicts H₂ mole percent in gases produced from heavyhydrocarbon drum experiments.

[0257]FIG. 174 depicts API gravity of liquids produced from heavyhydrocarbon drum experiments;

[0258]FIG. 175 depicts a plot of hydrocarbon liquids production overtime for an in situ field experiment;

[0259]FIG. 176 depicts a plot of hydrocarbon liquids, gas, and water foran in situ field experiment;

[0260]FIG. 177 depicts pressure at wellheads as a function of time froma numerical simulation;

[0261]FIG. 178 depicts production rate of carbon dioxide and methane asa function of time from a numerical simulation;

[0262]FIG. 179 depicts cumulative methane produced and net carbondioxide injected as a function of time from a numerical simulation;

[0263]FIG. 180 depicts pressure at wellheads as a function of time froma numerical simulation;

[0264]FIG. 181 depicts production rate of carbon dioxide as a functionof time from a numerical simulation; and

[0265]FIG. 182 depicts cumulative net carbon dioxide injected as afunction of time from a numerical simulation.

[0266] While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and may herein be described in detail. Thedrawings may not be to scale. It should be understood, however, that thedrawings and detailed description thereto are not intended to limit theinvention to the particular form disclosed, but on the contrary, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the present invention as definedby the appended claims.

DETAILED DESCRIPTION OF THE INVENTION

[0267] The following description generally relates to systems andmethods for treating a hydrocarbon containing formation (e.g., aformation containing coal (including lignite, sapropelic coal, etc.),oil shale, carbonaceous shale, shungites, kerogen, oil, kerogen and oilin a low permeability matrix, heavy hydrocarbons, asphaltites, naturalmineral waxes, formations wherein kerogen is blocking production ofother hydrocarbons, etc.). Such formations may be treated to yieldrelatively high quality hydrocarbon products, hydrogen, and otherproducts.

[0268] As used herein, “a method of treating a hydrocarbon containingformation” may be used interchangeably with “an in situ conversionprocess for hydrocarbons.” “Hydrocarbons” are generally defined asorganic material that contains carbon and hydrogen in their molecularstructures. Hydrocarbons may also include other elements, such as, butnot limited to, halogens, metallic elements, nitrogen, oxygen, and/orsulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen,pyrobitumen, and oils. Hydrocarbons may be located within or adjacent tomineral matrices within the earth. Matrices may include, but are notlimited to, sedimentary rock, sands, silicilytes, carbonates,diatomites, and other porous media.

[0269] “Kerogen” is generally defined as a solid, insoluble hydrocarbonthat has been converted by natural degradation (e.g., by diagenesis) andthat principally contains carbon, hydrogen, nitrogen, oxygen, andsulfur. Coal and oil shale are typical examples of materials thatcontain kerogens. “Bitumen” is generally defined as a non-crystallinesolid or viscous hydrocarbon material that is substantially soluble incarbon disulphide. “Oil” is generally defined as a fluid containing acomplex mixture of condensable hydrocarbons.

[0270] The terms “formation fluids” and “produced fluids” generallyrefer to fluids removed from a hydrocarbon containing formation and mayinclude pyrolyzation fluid, synthesis gas, mobilized hydrocarbon, andwater (steam). The term “mobilized fluid” generally refers to fluidswithin the formation that are able to flow because of thermal treatmentof the formation. Formation fluids may include hydrocarbon fluids aswell as non-hydrocarbon fluids. As used herein, “hydrocarbon fluids”generally refer to compounds including primarily hydrogen and carbon.Hydrocarbon fluids may include other elements in addition to hydrogenand carbon such as, but not limited to, nitrogen, oxygen, and sulfur.Non-hydrocarbon fluids may include, but are not limited to, hydrogen(“H₂“), nitrogen (“N₂“), carbon monoxide, carbon dioxide, hydrogensulfide, water, and ammonia.

[0271] A “carbon number” generally refers to a number of carbon atomswithin a molecule. As described herein, carbon number distributions aredetermined by true boiling point distribution and gas liquidchromatography.

[0272] A “heat source” is generally defined as any system configured toprovide heat to at least a portion of a formation. For example, a heatsource may include electrical heaters such as an insulated conductor, anelongated member, and a conductor disposed within a conduit, asdescribed in embodiments herein. A heat source may also include heatsources that generate heat by burning a fuel external to or within aformation such as surface burners, flameless distributed combustors, andnatural distributed combustors, as described in embodiments herein. Inaddition, it is envisioned that in some embodiments heat provided to orgenerated in one or more heat sources may by supplied by other sourcesof energy. The other sources of energy may directly heat a formation, orthe energy may be applied to a transfer media that directly orindirectly heats the formation. It is to be understood that one or moreheat sources that are applying heat to a formation may use differentsources of energy. Thus, for example, for a given formation some heatsources may supply heat from electric resistance heaters, some heatsources may provide heat from combustion, and some heat sources mayprovide heat from one or more other energy sources (e.g., chemicalreactions, solar energy, wind energy, or other sources of renewableenergy). A chemical reaction may include an exothermic reaction such as,but not limited to, an oxidation reaction that may take place in atleast a portion of a formation. A heat source may also include a heaterthat may be configured to provide heat to a zone proximate to and/orsurrounding a heating location such as a heater well. Heaters may be,but are not limited to, electric heaters, burners, and naturaldistributed combustors.

[0273] A “heater” is generally defined as any system configured togenerate heat in a well or a near wellbore region. A “unit of heatsources” refers to a minimal number of heat sources that form a templatethat is repeated to create a pattern of heat sources within a formation.For example, a heater may generate heat by burning a fuel external to orwithin a formation such as surface burners, flameless distributedcombustors, and natural distributed combustors, as described inembodiments herein.

[0274] The term “wellbore” generally refers to a hole in a formationmade by drilling. A wellbore may have a substantially circularcross-section, or a cross-section in other shapes as well (e.g.,circles, ovals, squares, rectangles, triangles, slits, or other regularor irregular shapes). As used herein, the terms “well” and “opening,”when referring to an opening in the formation, may also be usedinterchangeably with the term “wellbore.”

[0275] As used herein, the phrase “natural distributed combustor”generally refers to a heater that uses an oxidant to oxidize at least aportion of the carbon in the formation to generate heat, and wherein theoxidation takes place in a vicinity proximate to a wellbore. Most of thecombustion products produced in the natural distributed combustor areremoved through the wellbore.

[0276] The term “orifices,” as used herein, generally describes openingshaving a wide variety of sizes and cross-sectional shapes including, butnot limited to, circles, ovals, squares, rectangles, triangles, slits,or other regular or irregular shapes.

[0277] As used herein, a “reaction zone” generally refers to a volume ofa hydrocarbon containing formation that is subjected to a chemicalreaction such as an oxidation reaction.

[0278] As used herein, the term “insulated conductor” generally refersto any elongated material that may conduct electricity and that iscovered, in whole or in part, by an electrically insulating material.The term “self-controls” generally refers to controlling an output of aheater without external control of any type.

[0279] “Pyrolysis” is generally defined as the breaking of chemicalbonds due to the application of heat. For example, pyrolysis may includetransforming a compound into one or more other substances by heat alone.In the context of this patent, heat for pyrolysis may originate in anoxidation reaction and then such heat may be transferred to a section ofthe formation to cause pyrolysis.

[0280] As used herein, a “pyrolyzation fluid” or “pyrolysis products”generally refers to a fluid produced substantially during pyrolysis ofhydrocarbons. As used herein, a “pyrolysis zone” generally refers to avolume of hydrocarbon containing formation that is reacted or reactingto form a pyrolyzation fluid.

[0281] “Cracking” generally refers to a process involving decompositionand molecular recombination of organic compounds wherein a number ofmolecules becomes larger. In cracking, a series of reactions take placeaccompanied by a transfer of hydrogen atoms between molecules. Crackingfundamentally changes the chemical structure of the molecules. Forexample, naphtha may undergo a thermal cracking reaction to form etheneand H₂.

[0282] The term “superposition of heat” is generally defined asproviding heat from at least two heat sources to a selected section ofthe portion of the formation such that the temperature of the formationat least at one location between the two wells is influenced by at leasttwo heat sources.

[0283] The term “fingering” generally refers to injected fluidsbypassing portions of a formation because of variations in transportcharacteristics (e.g., permeability).

[0284] “Thermal conductivity” is generally defined as the property of amaterial that describes the rate at which heat flows, in steady state,between two surfaces of the material for a given temperature differencebetween the two surfaces.

[0285] “Fluid pressure” is generally defined as a pressure generated bya fluid within a formation. “Lithostatic pressure” is sometimes referredto as lithostatic stress and is generally defined as a pressure within aformation equal to a weight per unit area of an overlying rock mass.“Hydrostatic pressure” is generally defined as a pressure within aformation exerted by a column of water.

[0286] “Condensable hydrocarbons” means the hydrocarbons that condenseat 25° C. at one atmosphere absolute pressure. Condensable hydrocarbonsmay include a mixture of hydrocarbons having carbon numbers greater than4. “Non-condensable hydrocarbons” means the hydrocarbons that do notcondense at 25° C. and one atmosphere absolute pressure. Non-condensablehydrocarbons may include hydrocarbons having carbon numbers less than 5.

[0287] “Olefins” are generally defined as unsaturated hydrocarbonshaving one or more non-aromatic carbon-to-carbon double bonds.

[0288] “Urea” is generally described by a molecular formula ofNH₂—CO—NH₂. Urea can be used as a fertilizer.

[0289] “Synthesis gas” is generally defined as a mixture includinghydrogen and carbon monoxide used for synthesizing a wide range ofcompounds. Additional components of synthesis gas may include water,carbon dioxide, nitrogen, methane and other gases. Synthesis gas may begenerated by a variety of processes and feedstocks.

[0290] “Reforming” is generally defined as the reaction of hydrocarbons(such as methane or naphtha) with steam to produce CO and H₂ as majorproducts. Generally it is conducted in the presence of a catalystalthough it can be performed thermally without the presence of acatalyst. “Sequestration” generally refers to storing a gas that is aby-product of a process rather than venting the gas to the atmosphere.

[0291] The term “dipping” is generally defined as sloping downward orinclining from a plane parallel to the earth's surface, assuming theplane is flat (i.e., a “horizontal” plane). A “dip” is generally definedas an angle that a stratum or similar feature may make with a horizontalplane. A “steeply dipping” hydrocarbon containing formation generallyrefers to a hydrocarbon containing formation lying at an angle of atleast 20° from a horizontal plane. As used herein, “down dip” generallyrefers to downward along a direction parallel to a dip in a formation.As used herein, “up dip” generally refers to upward along a directionparallel to a dip of a formation. “Strike” refers to the course orbearing of hydrocarbon material that is normal to the direction of thedip.

[0292] The term “subsidence” is generally defined as downward movementof a portion of a formation relative to an initial elevation of thesurface.

[0293] “Thickness” of a layer refers to the thickness of a cross-sectionof a layer, wherein the cross-section is normal to a face of the layer.

[0294] “Coring” is generally defined as a process that generallyincludes drilling a hole into a formation and removing a substantiallysolid mass of the formation from the hole.

[0295] A “surface unit” is generally defined as an ex situ treatmentunit.

[0296] “Middle distillates” generally refers to hydrocarbon mixtureswith a boiling point range that may correspond substantially with thatof kerosene and gas oil fractions obtained in a conventional atmosphericdistillation of crude oil material. The middle distillate boiling pointrange may include temperatures between about 150° C. and about 360° C.,with a fraction boiling point between about 200° C. and about 360° C.Middle distillates may be referred to as gas oil.

[0297] A “boiling point cut” is generally defined as a hydrocarbonliquid fraction that may be separated from hydrocarbon liquids when thehydrocarbon liquids are heated to a boiling point range of the fraction.

[0298] The term “selected mobilized section” refers to a section of arelatively permeable formation that is at an average temperature withina mobilization temperature range. The term “selected pyrolyzationsection” refers to a section of a relatively permeable formation that isat an average temperature within a pyrolyzation temperature range.

[0299] “Enriched air” generally refers to air having a larger molefraction of oxygen than air in the atmosphere. Enrichment of air istypically done to increase its combustion-supporting ability.

[0300] “Heavy hydrocarbons” are generally defined as viscous hydrocarbonfluids. Heavy hydrocarbons may include highly viscous hydrocarbon fluidssuch as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may includecarbon and hydrogen, as well as smaller concentrations of sulfur,oxygen, and nitrogen. Additional elements may also be present in heavyhydrocarbons in trace amounts. Heavy hydrocarbons may be classified byAPI gravity. Heavy hydrocarbons generally have an API gravity belowabout 20°. Heavy oil, for example, generally has an API gravity of about10-20° whereas tar generally has an API gravity below about 10°. Theviscosity of heavy hydrocarbons is generally greater than about 300centipoise at 15° C. Tar generally has a viscosity greater than about10,000 centipoise at 15° C. Heavy hydrocarbons may also includearomatics, or other complex ring hydrocarbons.

[0301] Heavy hydrocarbons may be found in a relatively permeableformation. The relatively permeable formation may include heavyhydrocarbons entrained in, for example, sand or carbonate. “Relativelypermeable” is defined, with respect to formations or portions thereof,as an average permeability of 10 millidarcy or more (e.g., 10 or 100millidarcy). “Relatively low permeability” is defined, with respect toformations or portions thereof. as an average permeability of less thanabout 10 millidarcy. One Darcy is equal to about 0.99 squaremicrometers. An impermeable layer generally has a permeability of lessthan about 0.1 millidarcy.

[0302] The term “upgrade” refers to increasing the API gravity of heavyhydrocarbons.

[0303] The phrase “off peak” times generally refers to times ofoperation where utility energy is less commonly used and, therefore,less expensive.

[0304] The term “low viscosity zone” generally refers to a section of aformation where at least a portion of the fluids are mobilized.

[0305] Tar contained in sand in a formation is generally referred to asa “tar sand formation.”

[0306] “Thermal fracture” refers to fractures created in a formationcaused by expansion or contraction of a formation and/or fluids withinthe formation, which is in turn caused by increasing/decreasing thetemperature of the formation and/or fluids within the formation, and/orby increasing/decreasing a pressure of fluids within the formation dueto heating.

[0307] “Vertical hydraulic fracture” refers to a fracture at leastpartially propagated along a vertical plane in a formation, wherein thefracture is created through injection of fluids into a formation.

[0308] Hydrocarbons in formations may be treated in various ways toproduce many different products. In certain embodiments such formationsmay be treated in stages. FIG. 1 illustrates several stages of heating ahydrocarbon containing formation. FIG. 1 also depicts an example ofyield (barrels of oil equivalent per ton) (y axis) of formation fluidsfrom a hydrocarbon containing formation versus temperature (° C.) (xaxis) of the formation.

[0309] Desorption of methane and vaporization of water occurs duringstage 1 heating in FIG. 1. For example, when a hydrocarbon containingformation is initially heated, hydrocarbons in the formation may desorbadsorbed methane. The desorbed methane may be produced from theformation. If the hydrocarbon containing formation is heated further,water within the hydrocarbon containing formation may be vaporized. Inaddition, the vaporized water may be produced from the formation.Heating of the formation through stage 1 is in many instances preferablyperformed as quickly as possible.

[0310] After stage 1 heating, the formation may be heated further suchthat a temperature within the formation reaches (at least) an initialpyrolyzation temperature (e.g., the temperature at the lower end of thetemperature range shown as stage 2). A pyrolysis temperature range mayvary depending on types of hydrocarbons within the formation. Forexample, a pyrolysis temperature range may include temperatures betweenabout 250° C. and about 900° C. In an alternative embodiment, apyrolysis temperature range may include temperatures between about 270°C. to about 400° C. Hydrocarbons within the formation may be pyrolyzedthroughout stage 2.

[0311] Formation fluids including pyrolyzation fluids may be producedfrom the formation. The pyrolyzation fluids may include, but are notlimited to, hydrocarbons, hydrogen, carbon dioxide, carbon monoxide,hydrogen sulfide, ammonia, nitrogen, water and mixtures thereof. As thetemperature of the formation increases, the condensable hydrocarbons ofproduced formation fluid tends to decrease, and the formation will inmany instances tend to produce mostly methane and hydrogen. If ahydrocarbon containing formation is heated throughout an entirepyrolysis range, the formation may produce only small amounts ofhydrogen towards an upper limit of the pyrolysis range.

[0312] After all of the available hydrogen is depleted, a minimal amountof fluid production from the formation will typically occur.

[0313] After pyrolysis of hydrocarbons, a large amount of carbon andsome hydrogen may still be present in the formation. A significantportion of remaining carbon in the formation can be produced from theformation in the form of synthesis gas. Synthesis gas generation maytake place during stage 3 heating as shown in FIG. 1. Stage 3 mayinclude heating a hydrocarbon containing formation to a temperaturesufficient to allow synthesis gas generation. For example, synthesis gasmay be produced within a temperature range from about 400° C. to about1200° C. The temperature of the formation when the synthesis gasgenerating fluid is introduced to the formation will in many instancesdetermine the composition of synthesis gas produced within theformation. If a synthesis gas generating fluid is introduced into aformation at a temperature sufficient to allow synthesis gas generation,then synthesis gas may be generated within the formation. The generatedsynthesis gas may be removed from the formation. A large volume ofsynthesis gas may be produced during generation of synthesis gasgeneration.

[0314] Depending on the amounts of fluid produced, total energy contentof fluids produced from a hydrocarbon containing formation may in someinstances stay relatively constant throughout pyrolysis and synthesisgas generation. For example, during pyrolysis, at relatively lowformation temperatures, a significant portion of the produced fluid maybe condensable hydrocarbons that have a high energy content. At higherpyrolysis temperatures, however, less of the formation fluid may includecondensable hydrocarbons, and more non-condensable formation fluids maybe produced. In this manner, energy content per unit volume of theproduced fluid may decline slightly during generation of predominantlynon-condensable formation fluids. During synthesis gas generation,energy content per unit volume of produced synthesis gas declinessignificantly compared to energy content of pyrolyzation fluid. Thevolume of the produced synthesis gas, however, will in many instanceincrease substantially, thereby compensating for the decreased energycontent.

[0315] As explained below, the van Krevelen diagram shown in FIG. 2depicts a plot of atomic hydrogen to carbon ratio (y axis) versus atomicoxygen to carbon ratio (x axis) for various types of kerogen. Thisdiagram shows the maturation sequence for various types of kerogen thattypically occurs over geologic time due to temperature, pressure, andbiochemical degradation. The maturation may be accelerated by heating insitu at a controlled rate and/or a controlled pressure.

[0316] A van Krevelen diagram may be useful for selecting a resource forpracticing various embodiments described herein (see discussion below).Treating a formation containing kerogen in region 5 will in manyinstances produce, e.g., carbon dioxide, non-condensable hydrocarbons,hydrogen, and water, along with a relatively small amount of condensablehydrocarbons. Treating a formation containing kerogen in region 7 willin many instances produce, e.g., carbon condensable and non-condensablehydrocarbons, carbon dioxide, hydrogen, and water. Treating a formationcontaining kerogen in region 9 will in many instances produce, e.g.,methane and hydrogen. A formation containing kerogen in region 7, forexample, may in many instances be selected for treatment because doingso will tend to produce larger quantities of valuable hydrocarbons, andlower quantities of undesirable products such as carbon dioxide andwater, since the region 7 kerogen has already undergone dehydrationand/or decarboxylation over geological time. In addition, region 7kerogen can also be further treated to make other useful products (e.g.,methane, hydrogen, and/or synthesis gas) as such kerogen transforms toregion 9 kerogen.

[0317] If a formation containing kerogen in region 5 or 7 was selectedfor treatment, then treatment pursuant to certain embodiments describedherein would cause such kerogen to transform during treatment (seearrows in FIG. 2) to a region having a higher number (e.g., region 5kerogen could transform to region 7 kerogen and possibly then to region9 kerogen, or region 7 kerogen could transform to region 9 kerogen).Thus, certain embodiments described herein cause expedited maturation ofkerogen, thereby allowing production of valuable products.

[0318] If region 5 kerogen, for example, is treated, then substantialcarbon dioxide may be produced due to decarboxylation of hydrocarbons inthe formation. In addition, treating region 5 kerogen may also producesome hydrocarbons (e.g., primarily methane). Treating region 5 kerogenmay also produce substantial amounts of water due to dehydration ofkerogen in the formation. Production of such compounds from a formationmay leave residual hydrocarbons relatively enriched in carbon. Oxygencontent of the hydrocarbons will in many instances decrease faster thana hydrogen content of the hydrocarbons during production of suchcompounds. Therefore, as shown in FIG. 2, production of such compoundsmay result in a larger decrease in the atomic oxygen to carbon ratiothan a decrease in the atomic hydrogen to carbon ratio (see region 5arrows in FIG. 2 which depict more horizontal than vertical movement).

[0319] If region 7 kerogen is treated, then typically at least some ofthe hydrocarbons in the formation are pyrolyzed to produce condensableand non-condensable hydrocarbons. For example, treating region 7 kerogenmay result in production of oil from hydrocarbons, as well as somecarbon dioxide and water (albeit generally less carbon dioxide and waterthan is produced when the region 5 kerogen is treated). Therefore, theatomic hydrogen to carbon ratio of the kerogen will in many instancesdecrease rapidly as the kerogen in region 7 is treated. The atomicoxygen to carbon ratio of the region 7 kerogen, however, will in manyinstances decrease much slower than the atomic hydrogen to carbon ratioof the region 7 kerogen.

[0320] Kerogen in region 9 may be treated to generate methane andhydrogen. For example, if such kerogen was previously treated (e.g., itwas previously region 7 kerogen), then after pyrolysis longerhydrocarbon chains of the hydrocarbons may have already cracked andproduced from the formation. Carbon and hydrogen, however, may still bepresent in the formation.

[0321] If kerogen in region 9 were heated to a synthesis gas generatingtemperature and a synthesis gas generating fluid (e.g., steam) wereadded to the region 9 kerogen, then at least a portion of remaininghydrocarbons in the formation may be produced from the formation in theform of synthesis gas. For region 9 kerogen, the atomic hydrogen tocarbon ratio and the atomic oxygen to carbon ratio in the hydrocarbonsmay significantly decrease as the temperature rises. In this manner,hydrocarbons in the formation may be transformed into relatively purecarbon in region 9. Heating region 9 kerogen to still highertemperatures will tend to transform such kerogen into graphite 11.

[0322] A hydrocarbon containing formation may have a number ofproperties that will depend on, for example, a composition of at leastsome of the hydrocarbons within the formation. Such properties tend toaffect the composition and amount of products that are produced from ahydrocarbon containing formation. Therefore, properties of a hydrocarboncontaining formation can be used to determine if and/or how ahydrocarbon containing formation could optimally be treated.

[0323] Kerogen is composed of organic matter that has been transformeddue to a maturation process. Hydrocarbon containing formations thatinclude kerogen include, but are not limited to, coal containingformations and oil shale containing formations. Examples of hydrocarboncontaining formations that may not include kerogen are formationscontaining heavy hydrocarbons (e.g., tar sands). The maturation processmay include two stages: a biochemical stage and a geochemical stage. Thebiochemical stage typically involves degradation of organic material byboth aerobic and anaerobic organisms. The geochemical stage typicallyinvolves conversion of organic matter due to temperature changes andsignificant pressures. During maturation, oil and gas may be produced asthe organic matter of the kerogen is transformed.

[0324] The van Krevelen diagram shown in FIG. 2 classifies variousnatural deposits of kerogen. For example, kerogen may be classified intofour distinct groups: type I, type II, type III, and type IV, which areillustrated by the four branches of the van Krevelen diagram. Thisdrawing shows the maturation sequence for kerogen, which typicallyoccurs over geological time due to temperature and pressure. The typesdepend upon precursor materials of the kerogen. The precursor materialstransform over time into macerals, which are microscopic structures thathave different structures and properties based on the precursormaterials from which they are derived. Oil shale may be described as akerogen type I or type H and may primarily contain macerals from theliptinite group. Liptinites are derived from plants, specifically thelipid rich and resinous parts. The concentration of hydrogen withinliptinite may be as high as 9 weight %. In addition, liptinite has arelatively high hydrogen to carbon ratio and a relatively low atomicoxygen to carbon ratio. A type I kerogen may also be further classifiedas an alginite, since type I kerogen may include primarily algal bodies.Type I kerogen may result from deposits made in lacustrine environments.Type II kerogen may develop from organic matter that was deposited inmarine environments.

[0325] Type III kerogen may generally include vitrinite macerals.Vitrinite is derived from cell walls and/or woody tissues (e.g., stems,branches, leaves and roots of plants). Type III kerogen may be presentin most humic coals. Type III kerogen may develop from organic matterthat was deposited in swamps. Type IV kerogen includes the inertinitemaceral group. This group is composed of plant material such as leaves,bark and stems that have undergone oxidation during the early peatstages of burial diagenesis. It is chemically similar to vitrinite buthas a high carbon and low hydrogen content. Thus, it is consideredinert.

[0326] The dashed lines in FIG. 2 correspond to vitrinite reflectance.The vitrinite reflectance is a measure of maturation. As kerogenundergoes maturation, the composition of the kerogen usually changes.For example, as kerogen undergoes maturation, volatile matter of kerogentends to decrease. Rank classifications of kerogen indicate the level towhich kerogen has matured. For example, as kerogen undergoes maturation,the rank of kerogen increases. Therefore, as rank increases, thevolatile matter of kerogen tends to decrease. In addition, the moisturecontent of kerogen generally decreases as the rank increases. At higherranks, however, the moisture content may become relatively constant. Forexample, higher rank kerogens that have undergone significantmaturation, such as semi-anthracite or anthracite coal, tend to have ahigher carbon content and a lower volatile matter content than lowerrank kerogens such as lignite. For example, rank stages of coalcontaining formations include the following classifications, which arelisted in order of increasing rank and maturity for type III kerogen:wood, peat, lignite, sub-bituminous coal, high volatile bituminous coal,medium volatile bituminous coal, low volatile bituminous coal,semi-anthracite, and anthracite. In addition, as rank increases, kerogentends to exhibit an increase in aromatic nature.

[0327] Hydrocarbon containing formations may be selected for in situtreatment based on properties of at least a portion of the formation.For example, a formation may be selected based on richness, thickness,and depth (i.e., thickness of overburden) of the formation. In addition,a formation may be selected that will have relatively high qualityfluids produced from the formation. In certain embodiments the qualityof the fluids to be produced may be assessed in advance of treatment,thereby generating significant cost savings since only more optimalformations will be selected for treatment. Properties that may be usedto assess hydrocarbons in a formation include, but are not limited to,an amount of hydrocarbon liquids that tend to be produced from thehydrocarbons, a likely API gravity of the produced hydrocarbon liquids,an amount of hydrocarbon gas that tend to be produced from thehydrocarbons, and/or an amount of carbon dioxide and water that tend tobe produced from the hydrocarbons.

[0328] Another property that may be used to assess the quality of fluidsproduced from certain kerogen containing formations is vitrinitereflectance. Such formations include, but are not limited to, coalcontaining formations and oil shale containing formations. Hydrocarboncontaining formations that include kerogen can typically beassessed/selected for treatment based on a vitrinite reflectance of thekerogen. Vitrinite reflectance is often related to a hydrogen to carbonatomic ratio of a kerogen and an oxygen to carbon atomic ratio of thekerogen, as shown by the dashed lines in FIG. 2. For example, a vanKrevelen diagram may be useful in selecting a resource for an in situconversion process.

[0329] Vitrinite reflectance of a kerogen in a hydrocarbon containingformation tends to indicate which fluids may be produced from aformation upon heating. For example, a vitrinite reflectance ofapproximately 0.5% to approximately 1.5% tends to indicate a kerogenthat, upon heating, will produce fluids as described in region 7 above.Therefore, if a hydrocarbon containing formation having such kerogen isheated, a significant amount (e.g., majority) of the fluid produced bysuch heating will often include oil and other such hydrocarbon fluids.In addition, a vitrinite reflectance of approximately 1.5% to 3.0% mayindicate a kerogen in region 9 as described above. If a hydrocarboncontaining formation having such kerogen is heated, a significant amount(e.g., majority) of the fluid produced by such heating may includemethane and hydrogen (and synthesis gas, if, for example, thetemperature is sufficiently high and steam is injected). In anembodiment, at least a portion of a hydrocarbon containing formationselected for treatment in situ has a vitrinite reflectance in a rangebetween about 0.2% and about 3.0%. Alternatively, at least a portion ofa hydrocarbon containing formation selected for treatment has avitrinite reflectance from about 0.5% to about 2.0%, and, in somecircumstances, the vitrinite reflectance may range from about 0.5% to1.0%. Such ranges of vitrinite reflectance tend to indicate thatrelatively higher quality formation fluids will be produced from theformation.

[0330] In an embodiment, a hydrocarbon containing formation may beselected for treatment based on a hydrogen content within thehydrocarbons in the formation. For example, a method of treating ahydrocarbon containing formation may include selecting a portion of thehydrocarbon containing formation for treatment having hydrocarbons witha hydrogen content greater than about 3 weight %, 3.5 weight %, or 4weight % when measured on a dry, ash-free basis. In addition, a selectedsection of a hydrocarbon containing formation may include hydrocarbonswith an atomic hydrogen to carbon ratio that falls within a range fromabout 0.5 to about 2, and in many instances from about 0.70 to about1.65.

[0331] Hydrogen content of a hydrocarbon containing formation maysignificantly affect a composition of hydrocarbon fluids produced from aformation. For example, pyrolysis of at least some of the hydrocarbonswithin the heated portion may generate hydrocarbon fluids that mayinclude a double bond or a radical. Hydrogen within the formation mayreduce the double bond to a single bond. In this manner, reaction ofgenerated hydrocarbon fluids with each other and/or with additionalcomponents in the formation may be substantially inhibited. For example,reduction of a double bond of the generated hydrocarbon fluids to asingle bond may reduce polymerization of the generated hydrocarbons.Such polymerization tends to reduce the amount of fluids produced.

[0332] In addition, hydrogen within the formation may also neutralizeradicals in the generated hydrocarbon fluids. In this manner, hydrogenpresent in the formation may substantially inhibit reaction ofhydrocarbon fragments by transforming the hydrocarbon fragments intorelatively short chain hydrocarbon fluids. The hydrocarbon fluids mayenter a vapor phase and may be produced from the formation. The increasein the hydrocarbon fluids in the vapor phase may significantly reduce apotential for producing less desirable products within the selectedsection of the formation.

[0333] It is believed that if too little hydrogen is present in theformation, then the amount and quality of the produced fluids will benegatively affected. If too little hydrogen is naturally present, thenin some embodiments hydrogen or other reducing fluids may be added tothe formation.

[0334] When heating a portion of a hydrocarbon containing formation,oxygen within the portion may form carbon dioxide. It may be desirableto reduce the production of carbon dioxide and other oxides. In anembodiment, production of carbon dioxide may be reduced by selecting andtreating a portion of a hydrocarbon containing formation having avitrinite reflectance of greater than about 0.5%. In addition, an amountof carbon dioxide produced from a formation may vary depending on, forexample, an oxygen content of a treated portion of the hydrocarboncontaining formation. Certain embodiments may thus include selecting andtreating a portion of the formation having a kerogen with an atomicoxygen weight percentage of less than about 20%, 15%, and/or 10%. Inaddition, certain embodiments may include selecting and processing aformation containing kerogen with an atomic oxygen to carbon ratio ofless than about 0.15. Alternatively, at least some of the hydrocarbonsin a portion of a formation selected for treatment may have an atomicoxygen to carbon ratio of about 0.03 to about 0.12. In this manner,production of carbon dioxide and other oxides from an in situ conversionprocess for hydrocarbons may be reduced.

[0335] Heating a hydrocarbon containing formation may include providinga large amount of energy to heat sources located within the formation.Hydrocarbon containing formations may contain water. Water present inthe hydrocarbon containing formation will tend to further increase theamount of energy required to heat a hydrocarbon containing formation. Inthis manner, water tends to hinder efficient heating of the formation.For example, a large amount of energy may be required to evaporate waterfrom a hydrocarbon containing formation. Thus, an initial rate oftemperature increase may be reduced by the presence of water in theformation. Therefore, excessive amounts of heat and/or time may berequired to heat a formation having a high moisture content to atemperature sufficient to allow pyrolysis of at least some of thehydrocarbons in the formation. In an embodiment, an in situ conversionprocess for hydrocarbons may include selecting a portion of thehydrocarbon containing formation for treatment having an initialmoisture content of less than about 15% by weight (in some embodimentsdewatering wells may be used to reduce the water content of theformation). Alternatively, an in situ conversion process forhydrocarbons may include selecting a portion of the hydrocarboncontaining formation for treatment having an initial moisture content ofless than about 10% by weight.

[0336] In an embodiment, a hydrocarbon containing formation may beselected for treatment based on additional factors such as a thicknessof hydrocarbon containing layer within the formation and assessed liquidproduction content. For example, a hydrocarbon containing formation mayinclude multiple layers. Such layers may include hydrocarbon containinglayers, and also layers that may be hydrocarbon free or havesubstantially low amounts of hydrocarbons. Each of the hydrocarboncontaining layers may have a thickness that may vary depending on, forexample, conditions under which the hydrocarbon containing layer wasformed. Therefore, a hydrocarbon containing formation will typically beselected for treatment if that formation includes at least onehydrocarbon containing layer having a thickness sufficient foreconomical production of formation fluids. A formation may also bechosen if the thickness of several layers that are closely spacedtogether is sufficient for economical production of formation fluids.Other formations may also be chosen based on a richness of thehydrocarbon resource within the soil, even if the thickness of theresource is relatively thin.

[0337] In addition, a layer of a hydrocarbon containing formation may beselected for treatment based on a thickness of the hydrocarboncontaining layer, and/or a total thickness of hydrocarbon containinglayers in a formation. For example, an in situ conversion process forhydrocarbons may include selecting and treating a layer of a hydrocarboncontaining formation having a thickness of greater than about 2 m, 3 m,and/or 5 m. In this manner, heat losses (as a fraction of total injectedheat) to layers formed above and below a layer of hydrocarbons may beless than such heat losses from a thin layer of hydrocarbons. A processas described herein, however, may also include selecting and treatinglayers that may include layers substantially free of hydrocarbons andthin layers of hydrocarbons.

[0338] Each of the hydrocarbon containing layers may also have apotential formation fluid yield that may vary depending on, for example,conditions under which the hydrocarbon containing layer was formed, anamount of hydrocarbons in the layer, and/or a composition ofhydrocarbons in the layer. A potential formation fluid yield may bemeasured, for example, by the Fischer Assay. The Fischer Assay is astandard method which involves heating a sample of a hydrocarboncontaining layer to approximately 500° C. in one hour, collectingproducts produced from the heated sample, and quantifying the amount ofproducts produced. A sample of a hydrocarbon containing layer may beobtained from a hydrocarbon containing formation by a method such ascoring or any other sample retrieval method.

[0339]FIG. 3 shows a schematic view of an embodiment of a portion of anin situ conversion system for treating a hydrocarbon containingformation. Heat sources 100 may be placed within at least a portion ofthe hydrocarbon containing formation. Heat sources 100 may include, forexample, electrical heaters such as insulated conductors,conductor-in-conduit heaters, surface burners, flameless distributedcombustors, and/or natural distributed combustors. Heat sources 100 mayalso include other types of heaters. Heat sources 100 are configured toprovide heat to at least a portion of a hydrocarbon containingformation. Energy may be supplied to the heat sources 100 through supplylines 102. The supply lines may be structurally different depending onthe type of heat source or heat sources being used to heat theformation. Supply lines for heat sources may transmit electricity forelectrical heaters, may transport fuel for combustors, or may transportheat exchange fluid that is circulated within the formation.

[0340] Production wells 104 may be used to remove formation fluid fromthe formation. Formation fluid produced from the production wells 104may be transported through collection piping 106 to treatment facilities108. Formation fluids may also be produced from heat sources 100. Forexample, fluid may be produced from heat sources 100 to control pressurewithin the formation adjacent to the heat sources. Fluid produced fromheat sources 100 may be transported through tubing or piping to thecollection piping 106 or the produced fluid may be transported throughtubing or piping directly to the treatment facilities 108. The treatmentfacilities 108 may include separation units, reaction units, upgradingunits, fuel cells, turbines, storage vessels, and other systems andunits for processing produced formation fluids.

[0341] An in situ conversion system for treating hydrocarbons mayinclude dewatering wells 110 (wells shown with reference number 110 may,in some embodiments, be capture and/or isolation wells). Dewateringwells 110 or vacuum wells may be configured to remove and inhibit liquidwater from entering a portion of a hydrocarbon containing formation tobe heated, or to a formation being heated. A plurality of water wellsmay surround all or a portion of a formation to be heated. In theembodiment depicted in FIG. 3, the dewatering wells 110 are shownextending only along one side of heat sources 100, but dewatering wellstypically encircle all heat sources 100 used, or to be used, to heat theformation.

[0342] Dewatering wells 110 may be placed in one or more ringssurrounding selected portions of the formation. New dewatering wells mayneed to be installed as an area being treated by the in situ conversionprocess expands. An outermost row of dewatering wells may inhibit asignificant amount of water from flowing into the portion of formationthat is heated or to be heated. Water produced from the outermost row ofdewatering wells should be substantially clean, and may require littleor no treatment before being released. An innermost row of dewateringwells may inhibit water that bypasses the outermost row from flowinginto the portion of formation that is heated or to be heated. Theinnermost row of dewatering wells may also inhibit outward migration ofvapor from a heated portion of the formation into surrounding portionsof the formation. Water produced by the innermost row of dewateringwells may include some hydrocarbons. The water may need to be treatedbefore being released. Alternately, water with hydrocarbons may bestored and used to produce synthesis gas from a portion of formationduring a synthesis gas phase of the in situ conversion process. Thedewatering wells may reduce heat loss to surrounding portions of theformation, may increase production of vapors from the heated portion,and may inhibit contamination of a water table proximate the heatedportion of the formation.

[0343] In an alternative embodiment, a fluid (e.g., liquid or gas) maybe injected in the innermost row of wells, allowing a selected pressureto be maintained in or about the pyrolysis zone. Additionally, thisfluid may act as an isolation barrier between the outermost wells andthe pyrolysis fluids, thereby improving the efficiency of the dewateringwells.

[0344] The hydrocarbons to be treated may be located under a large area.The in situ conversion system may be used to treat small portions of theformation, and other sections of the formation may be treated as timeprogresses. In an embodiment of a system for treating an oil shalecontaining formation, a field layout for 24 years of development may bedivided into 24 individual plots that represent individual drillingyears. Each plot may include 120 “tiles” (repeating matrix patterns)wherein each tile is made of 6 rows by 20 columns. Each tile may include1 production well and 12 or 18 heater wells. The heater wells may beplaced in an equilateral triangle pattern with, for example, a wellspacing of about 12 m. Production wells may be located in centers ofequilateral triangles of heater wells, or the production wells may belocated approximately at a midpoint between two adjacent heater wells.

[0345] In certain embodiments, heat sources will be placed within aheater well formed within a hydrocarbon containing formation. The heaterwell may include an opening through an overburden of the formation andinto at least one hydrocarbon containing section of the formation.Alternatively, as shown in FIG. 3a, heater well 224 may include anopening in formation 222 that may have a shape substantially similar toa helix or spiral . A spiral configuration for a heater well may in someembodiments increase the transfer of heat from the heat source and/orallow the heat source to expand when heated, without buckling or othermodes of failure. In some embodiments, such a heater well may alsoinclude a substantially straight section through overburden 220. Use ofa straight heater well through the overburden may decrease heat loss tothe overburden.

[0346] In an alternative embodiment, as shown in FIG. 3b, heat sourcesmay be placed into heater well 224 that may include an opening information 222 having a shape substantially similar to a “U” (the “legs”of the “U” may be wider or more narrow depending on the embodimentsused). First portion 226 and third portion 228 of heater well 224 may bearranged substantially perpendicular to an upper surface of formation222. In addition, the first and the third portion of the heater well mayextend substantially vertically through overburden 220. Second portion230 of heater well 224 may be substantially parallel to the uppersurface of the formation.

[0347] In addition, multiple heat sources (e.g., 2, 3, 4, 5, 10 heatsources or more) may extend from a heater well in some situations. Forexample, as shown in FIG. 3c, heat sources 232, 234, and 236 may extendthrough overburden 220 into formation 222 from heater well 224. Suchsituations may occur when surface considerations (e.g., aesthetics,surface land use concerns, and/or unfavorable soil conditions near thesurface) make it desirable to concentrate the surface facilities infewer locations. For example, in areas where the soil is frozen and/ormarshy it may be more cost-effective to have surface facilities locatedin a more centralized location.

[0348] In certain embodiments a first portion of a heater well mayextend from a surface of the ground, through an overburden, and into ahydrocarbon containing formation. A second portion of the heater wellmay include one or more heater wells in the hydrocarbon containingformation. The one or more heater wells may be disposed within thehydrocarbon containing formation at various angles. In some embodiments,at least one of heater wells may be disposed substantially parallel to aboundary of the hydrocarbon containing formation. In alternateembodiments, at least one of the heater wells may be substantiallyperpendicular to the hydrocarbon containing formation. In addition, oneof the one or more heater wells may be positioned at an angle betweenperpendicular and parallel to a layer in the formation.

[0349]FIG. 4 illustrates an embodiment of a hydrocarbon containingformation 200 that may be at a substantially near-horizontal angle withrespect to an upper surface of the ground 204. An angle of hydrocarboncontaining formation 200, however, may vary. For example, hydrocarboncontaining formation 200 may be steeply dipping. Economically viableproduction of a steeply dipping hydrocarbon containing formation may notbe possible using presently available mining methods. A relativelysteeply dipping hydrocarbon containing formation, however, may besubjected to an in situ conversion process as described herein. Forexample, a single set of gas producing wells may be disposed near a topof a steeply dipping hydrocarbon containing formation. Such a formationmay be heated by heating a portion of the formation proximate a top ofthe hydrocarbon containing formation and sequentially heating lowersections of the hydrocarbon containing formation. Gases may be producedfrom the hydrocarbon containing formation by transporting gases throughthe previously pyrolyzed hydrocarbons with minimal pressure loss.

[0350] In an embodiment, an in situ conversion process for hydrocarbonsmay include providing heat to at least a portion of a hydrocarboncontaining formation that dips in sections. For example, a portion ofthe formation may include a dip that may include a minimum depth of theportion. A production well may be located in the portion of thehydrocarbon containing formation proximate the minimum depth. Anadditional production well may not be required in the portion. Forexample, as heat transfers through the hydrocarbon containing formationand at least some hydrocarbons in the portion pyrolyze, pyrolyzationfluids formed in the portion may travel through pyrolyzed sections ofthe hydrocarbon containing formation to the production well. Asdescribed herein, increased permeability due to in situ treatment of ahydrocarbon containing formation may increase transfer of vapors throughthe treated portion of the formation. Therefore, a number of productionwells required to produce a mixture from the formation may be reduced.Reducing the number of production wells required for production mayincrease economic viability of an in situ conversion process.

[0351] In steeply dipping formations, directional drilling may be usedto form an opening for a heater well in the formation. Directionaldrilling may include drilling an opening in which the route/course ofthe opening may be planned before drilling. Such an opening may usuallybe drilled with rotary equipment. In directional drilling, aroute/course of an opening may be controlled by deflection wedges, etc.

[0352] Drilling heater well 202 may also include drilling an opening inthe formation with a drill equipped with a steerable motor and anaccelerometer that may be configured to follow hydrocarbon containingformation 200. For example, a steerable motor may be configured tomaintain a substantially constant distance between heater well 202 and aboundary of hydrocarbon containing formation 200 throughout drilling ofthe opening. Drilling of heater well 202 with the steerable motor andthe accelerometer may be relatively economical.

[0353] Alternatively, geosteered drilling may be used to drill heaterwell 202 into hydrocarbon containing formation 200. Geosteered drillingmay include determining or estimating a distance from an edge ofhydrocarbon containing formation 200 to heater well 202 with a sensor.The sensor may include, but may not be limited to, sensors that may beconfigured to determine a distance from an edge of hydrocarboncontaining formation 200 to heater well 202. In addition, such a sensormay be configured to determine and monitor a variation in acharacteristic of the hydrocarbon containing formation 200. Such sensorsmay include, but may not be limited to, sensors that may be configuredto measure a characteristic of a hydrocarbon seam using resistance,gamma rays, acoustic pulses, and/or other devices. Geosteered drillingmay also include forming an opening for a heater well with a drillingapparatus that may include a steerable motor. The motor may becontrolled to maintain a predetermined distance from an edge of ahydrocarbon containing formation. In an additional embodiment, drillingof a heater well or any other well in a formation may also include sonicdrilling.

[0354]FIG. 5 illustrates an embodiment of a plurality of heater wells210 formed in hydrocarbon containing formation 212. Hydrocarboncontaining formation 212 may be a steeply dipping formation. One or moreof the heater wells 210 may be formed in the formation such that two ormore of the heater wells are substantially parallel to each other,and/or such that at least one heater well is substantially parallel tohydrocarbon containing formation 212. For example, one or more of theheater wells 210 may be formed in hydrocarbon containing formation 212by a magnetic steering method. An example of a magnetic steering methodis illustrated in U.S. Pat. No. 5,676,212 to Kuckes, which isincorporated by reference as if fully set forth herein. Magneticsteering may include drilling heater well 210 parallel to an adjacentheater well. The adjacent well may have been previously drilled. Inaddition, magnetic steering may include directing the drilling bysensing and/or determining a magnetic field produced in an adjacentheater well. For example, the magnetic field may be produced in theadjacent heater well by flowing a current through an insulatedcurrent-carrying wireline disposed in the adjacent heater well.Alternatively, one or more of the heater wells 210 may be formed by amethod as is otherwise described herein. A spacing between heater wells210 may be determined according to any of the embodiments describedherein.

[0355] In some embodiments, heated portion 310 may extend substantiallyradially from heat source 300, as shown in FIG. 6. For example, a widthof heated portion 310, in a direction extending radially from heatsource 300, may be about 0 m to about 10 m . A width of heated portion310 may vary, however, depending upon; for example, heat provided byheat source 300 and the characteristics of the formation. Heat providedby heat source 300 will typically transfer through the heated portion tocreate a temperature gradient within the heated portion. For example, atemperature proximate the heater well will generally be higher than atemperature proximate an outer lateral boundary of the heated portion. Atemperature gradient within the heated portion, however, may vary withinthe heated portion depending on, for example, the thermal conductivityof the formation.

[0356] As heat transfers through heated portion 310 of the hydrocarboncontaining formation, a temperature within at least a section of theheated portion may be within a pyrolysis temperature range. In thismanner, as the heat transfers away from the heat source, a front atwhich pyrolysis occurs will in many instances travel outward from theheat source. For example, heat from the heat source may be allowed totransfer into a selected section of the heated portion such that heatfrom the heat source pyrolyzes at least some of the hydrocarbons withinthe selected section. As such, pyrolysis may occur within selectedsection 315 of the heated portion, and pyrolyzation fluids will begenerated from hydrocarbons in the selected section. An inner lateralboundary of selected section 315 may be radially spaced from the heatsource. For example, an inner lateral boundary of selected section 315may be radially spaced from the heat source by about 0 m to about 1 m.In addition, selected section 315 may have a width radially extendingfrom the inner lateral boundary of the selected section. For example, awidth of the selected section may be at least approximately 1.5 m, atleast approximately 2.4 m, or even at least approximately 3.0 m. A widthof the selected section, however, may also be greater than approximately1.5 m and less than approximately 10 m.

[0357] After pyrolyzation of hydrocarbons in a portion of the selectedsection is complete, a section of spent hydrocarbons 317 may begenerated proximate to the heat source.

[0358] In some embodiments, a plurality of heated portions may existwithin a unit of heat sources. A unit of heat sources refers to aminimal number of heat sources that form a template that may be repeatedto create a pattern of heat sources within the formation. The heatsources may be located within the formation such that superposition(overlapping) of heat produced from the heat sources is effective. Forexample, as illustrated in FIG. 7, transfer of heat from two or moreheat sources 330 results in superposition of heat 332 to be effectivewithin an area defined by the unit of heat sources. Superposition mayalso be effective within an interior of a region defined by two, three,four, five, six or more heat sources. For example, an area in whichsuperposition of heat 332 is effective includes an area to whichsignificant heat is transferred by two or more heat sources of the unitof heat sources. An area in which superposition of heat is effective mayvary depending upon, for example, the spacings between heat sources.

[0359] Superposition of heat may increase a temperature in at least aportion of the formation to a temperature sufficient for pyrolysis ofhydrocarbon within the portion. In this manner, superposition of heat332 tends to increase the amount of hydrocarbon in a formation that maybe pyrolyzed. As such, a plurality of areas that are within a pyrolysistemperature range may exist within the unit of heat sources. Theselected sections 334 may include areas at a pyrolysis temperature rangedue to heat transfer from only one heat source, as well as areas at apyrolysis temperature range due to superposition of heat.

[0360] In addition, a pattern of heat sources will often include aplurality of units of heat sources. There will typically be a pluralityof heated portions, as well as selected sections within the pattern ofheat sources. The plurality of heated portions and selected sections maybe configured as described herein. Superposition of heat within apattern of heat sources may decrease the time necessary to reachpyrolysis temperatures within the multitude of heated portions.Superposition of heat may allow for a relatively large spacing betweenadjacent heat sources, which may in turn provide a relatively slow rateof heating of the hydrocarbon containing formation. In certainembodiments, superposition of heat will also generate fluidssubstantially uniformly from a heated portion of a hydrocarboncontaining formation.

[0361] In certain embodiments, a majority of pyrolysis fluids may beproduced when the selected section is within a range from about 0 m toabout 25 m from a heat source.

[0362] As shown in FIG. 3, in addition to heat sources 100, one or moreproduction wells 102 will typically be disposed within the portion ofthe hydrocarbon containing formation. Production well 102 may beconfigured such that a mixture that may include formation fluids may beproduced through the production well. Production well 102 may alsoinclude a heat source. In this manner, the formation fluids may bemaintained at a selected temperature throughout production, therebyallowing more or all of the formation fluids to be produced as vapors.Therefore high temperature pumping of liquids from the production wellmay be reduced or substantially eliminated, which in turn decreasesproduction costs. Providing heating at or through the production welltends to: (1) prevent condensation and/or refluxing of production fluidwhen such production fluid is moving in the production well proximate tothe overburden, (2) increase heat input into the formation, and/or (3)increase formation permeability at or proximate the production well.

[0363] Because permeability and/or porosity increase in the heatedformation, produced vapors may flow considerable distances through theformation with relatively little pressure differential. Therefore, insome embodiments, production wells may be provided near an upper surfaceof the formation. Increases in permeability may result from a reductionof mass of the heated portion due to vaporization of water, removal ofhydrocarbons, and/or creation of fractures. In this manner, fluids maymore easily flow through the heated portion.

[0364] For example, fluid generated within a hydrocarbon containingformation may move a considerable distance through the hydrocarboncontaining formation as a vapor. Such a considerable distance mayinclude, for example, about 50 m to about 1000 m. The vapor may have arelatively small pressure drop across the considerable distance due tothe permeability of the heated portion of the formation. In addition,due to such permeability, a production well may only need to be providedin every other unit of heat sources or every third, fourth, fifth, sixthunits of heat sources. Furthermore, as shown in FIG. 4, production wells206 may extend through a hydrocarbon containing formation near the topof heated portion 208.

[0365] Embodiments of production well 102 may include valves configuredto alter, maintain, and/or control a pressure of at least a portion ofthe formation. Production wells may be cased wells that may haveproduction screens or perforated casings adjacent to production zones.In addition, the production wells may be surrounded by sand, gravel orother packing material adjacent to production zones. Furthermore,production wells 102 may be coupled to treatment section 108, as shownin FIG. 3. Treatment section 108 may include any of the surfacefacilities as described herein.

[0366] In addition, water pumping wells or vacuum wells may beconfigured to remove liquid water from a portion of a hydrocarboncontaining formation to be heated. Water removed from the formation maybe used on the surface, and/or monitored for water quality. For example,a plurality of water wells may surround all or a portion of a formationto be heated. The plurality of water wells may be configured in one ormore rings surrounding the portion of the formation. An outermost row ofwater wells may inhibit a significant amount of water from flowing intothe portion to be heated. An innermost row of water wells may inhibitwater that bypasses the outermost row from flowing into the portion tobe heated. The innermost row of water wells may also inhibit outwardmigration of vapor from a heated portion of the formation intosurrounding portions of the formation. In this manner, the water wellsmay reduce heat loss to surrounding portions of the formation, mayincrease production of vapors from the heated portion, and may inhibitcontamination of a water table proximate to the heated portion of theformation. In some embodiments pressure differences between successiverows of dewatering wells may be minimized (e.g., maintained or nearzero) to create a “no or low flow” boundary between rows.

[0367] In certain embodiments, wells initially used for one purpose maybe later used for one or more other purposes, thereby lowering projectcosts and/or decreasing the time required to perform certain tasks. Forinstance, production wells (and in some circumstances heater wells) mayinitially be used as dewatering wells (e.g., before heating is begunand/or when heating is initially started). In addition, in somecircumstances dewatering wells can later be used as production wells(and in some circumstances heater wells). As such, the dewatering wellsmay be placed and/or designed so that such wells can be later used asproduction wells and/or heater wells. The heater wells may be placedand/or designed so that such wells can be later used as production wellsand/or dewatering wells. The production wells may be placed and/ordesigned so that such wells can be later used as dewatering wells and/orheater wells. Similarly, injection wells may be wells that initiallywere used for other purposes (e.g., heating, production, dewatering,monitoring, etc.), and injection wells may later be used for otherpurposes. Similarly, monitoring wells may be wells that initially wereused for other purposes (e.g., heating, production, dewatering,injection, etc.), and monitoring wells may later be used for otherpurposes.

[0368]FIG. 8 illustrates a pattern of heat sources 400 and productionwells 402 that may be configured to treat a hydrocarbon containingformation. Heat sources 400 may be arranged in a unit of heat sourcessuch as triangular pattern 401. Heat sources 400, however, may bearranged in a variety of patterns including, but not limited to,squares, hexagons, and other polygons. The pattern may include a regularpolygon to promote uniform heating through at least the portion of theformation in which the heat sources are placed. The pattern may also bea line drive pattern. A line drive pattern generally includes a firstlinear array of heater wells. a second linear array of heater wells, anda production well or a linear array of production wells between thefirst and second linear array of heater wells.

[0369] A distance from a node of a polygon to a centroid of the polygonis smallest for a 3 sided polygon and increases with increasing numberof sides of the polygon. The distance from a node to the centroid for anequilateral triangle is (length/2)/(square root(3)/2) or 0.5774 timesthe length. For a square, the distance from a node to the centroid is(length/2)/(square root(2)/2) or 0.7071 times the length. For a hexagon,the distance from a node to the centroid is (length/2)(½) or the length.The difference in distance between a heat source and a mid point to asecond heat sources (length/2) and the distance from a heat source tothe centroid for an equilateral pattern (0.5774 times the length) issignificantly less for the equilateral triangle pattern than for anyhigher order polygon pattern. The small difference means thatsuperposition of heat may develop more rapidly and that formationbetween heat sources may rise to a substantially more uniformtemperature using an equilateral triangle pattern rather than a higherorder polygon pattern.

[0370] Triangular patterns tend to provide more uniform heating to aportion of the formation in comparison to other patterns such as squaresand/or hexagons. Triangular patterns tend to provide faster heating to apredetermined temperature in comparison to other patterns such assquares and/or hexagons. Triangle patterns may also result in a smallvolume of the portion that are overheated. A plurality of units of heatsources such as triangular pattern 401 may be arranged substantiallyadjacent to each other to form a repetitive pattern of units over anarea of the formation. For example, triangular patterns 401 may bearranged substantially adjacent to each other in a repetitive pattern ofunits by inverting an orientation of adjacent triangles 401. Otherpatterns of heat sources 400 may also be arranged such that smallerpatterns may be disposed adjacent to each other to form larger patterns.

[0371] Production wells may be disposed in the formation in a repetitivepattern of units. In certain embodiments, production well 402 may bedisposed proximate to a center of every third triangle 401 arranged inthe pattern. Production well 402, however, may be disposed in everytriangle 401 or within just a few triangles. A production well may beplaced within every 13, 20, or 30 heater well triangles. For example, aratio of heat sources in the repetitive pattern of units to productionwells in the repetitive pattern of units may be more than approximately5 (e.g., more than 6, 7, 8, or 9). In addition, the placement ofproduction well 402 may vary depending on the heat generated by one ormore heat sources 400 and the characteristics of the formation (such aspermeability). Furthermore, three or more production wells may belocated within an area defined by a repetitive pattern of units. Forexample, as shown in FIG. 8, production wells 410 may be located withinan area defined by repetitive pattern of units 412. Production wells 410may be located in the formation in a unit of production wells. Forexample, the unit of production wells may be a triangular pattern.Production wells 410, however, may be disposed in another pattern withinrepetitive pattern of units 412.

[0372] In addition, one or more injection wells may be disposed within arepetitive pattern of units. The injection wells may be configured asdescribed herein. For example, as shown in FIG. 8, injection wells 414may be located within an area defined by repetitive pattern of units416. Injection wells 414 may also be located in the formation in a unitof injection wells. For example, the unit of injection wells may be atriangular pattern. Injection wells 414, however, may be disposed in anyother pattern as described herein. In certain embodiments, one or moreproduction wells and one or more injection wells may be disposed in arepetitive pattern of units. For example, as shown in FIG. 8, productionwells 418 and injection wells 420 may be located within an area definedby repetitive pattern of units 422. Production wells 418 may be locatedin the formation in a unit of production wells, which may be arranged ina first triangular pattern. In addition, injection wells 420 may belocated within the formation in a unit of production wells, which may bearranged in a second triangular pattern. The first triangular patternmay be substantially different than the second triangular pattern. Forexample, areas defined by the first and second triangular patterns maybe substantially different.

[0373] In addition, one or more monitoring wells may be disposed withina repetitive pattern of units. The monitoring wells may be configured asdescribed herein. For example, the wells may be configured with one ormore devices that measure a temperature, a pressure, and/or a propertyof a fluid. In some embodiments, logging tools may be placed inmonitoring well wellbores to measure properties within a formation. Thelogging tools may be moved to other monitoring well wellbores as needed.The monitoring well wellbores may be cased or uncased wellbores. Asshown in FIG. 8, monitoring wells 424 may be located within an areadefined by repetitive pattern of units 426. Monitoring wells 424 may belocated in the formation in a unit of monitoring wells, which may bearranged in a triangular pattern. Monitoring wells 424, however, may bedisposed in any of the other patterns as described herein withinrepetitive pattern of units 426.

[0374] It is to be understood that a geometrical pattern of heat sources400 and production wells 402 is described herein by example. A patternof heat sources and production wells will in many instances varydepending on, for example, the type of hydrocarbon containing formationto be treated. For example, for relatively thin layers heating wells maybe aligned along one or more layers along strike or along dip. Forrelatively thick layers, heat sources may be configured at an angle toone or more layers (e.g., orthogonally or diagonally).

[0375] A triangular pattern of heat sources may be configured to treat ahydrocarbon containing formation having a thickness of about 10 metersor more. For a thinner hydrocarbon containing formation, e.g., about 10meters thick or less, a line and/or staggered line pattern of heatsources may be configured to treat the hydrocarbon containing formation.

[0376] For certain thinner formations, heating wells may be placedcloser to an edge of the formation (e.g., in a staggered line instead ofline placed in the center of the layer) of the formation to increase theamount of hydrocarbons produced per unit of energy input. A portion ofinput heating energy may heat non-hydrocarbon containing formation, butthe staggered pattern may allow superposition of heat to heat a majorityof the hydrocarbon formation to pyrolysis temperatures. If the thinformation is heated by placing in the formation along a center of thethickness, a significant portion of the hydrocarbon containing formationmay not be heated to pyrolysis temperatures. In some embodiments,placing heater wells closer to an edge of the formation may increase thevolume of formation undergoing pyrolysis per unit of energy input.

[0377] In addition, the location of production well 402 within a patternof heat sources 400 may be determined by, for example, a desired heatingrate of the hydrocarbon containing formation, a heating rate of the heatsources, the type of heat sources used, the type of hydrocarboncontaining formation (and its thickness), the composition of thehydrocarbon containing formation, the desired composition to be producedfrom the formation, and/or a desired production rate. Exact placement ofheater wells, production wells, etc. will depend on variables specificto the formation (e.g., thickness of the layer, composition of thelayer, etc.). project economics, etc. In certain embodiments heaterwells may be substantially horizontal while production wells may bevertical, or vice versa.

[0378] Any of the wells described herein may be aligned along dip orstrike, or oriented at an angle between dip and strike.

[0379] The spacing between heat sources may also vary depending on anumber of factors that may include, but are not limited to, the type ofa hydrocarbon containing formation, the selected heating rate, and/orthe selected average temperature to be obtained within the heatedportion. For example, the spacing between heat sources may be within arange of about 5 m to about 25 m. Alternatively, the spacing betweenheat sources may be within a range of about 8 m to about 15 m.

[0380] The spacing between heat sources may influence the composition offluids produced from a hydrocarbon containing formation. In anembodiment. a computer-implemented method may be used to determineoptimum heat source spacings within a hydrocarbon containing formation.For example, at least one property of a portion of hydrocarboncontaining formation can usually be measured. The measured property mayinclude, but is not limited to, vitrinite reflectance, hydrogen content,atomic hydrogen to carbon ratio, oxygen content, atomic oxygen to carbonratio, water content, thickness of the hydrocarbon containing formation,and/or the amount of stratification of the hydrocarbon containingformation into separate layers of rock and hydrocarbons.

[0381] In certain embodiments a computer-implemented method may includeproviding at least one measured property to a computer system. One ormore sets of heat source spacings in the formation may also be providedto the computer system. For example, a spacing between heat sources maybe less than about 30 m. Alternatively, a spacing between heat sourcesmay be less than about 15 m. The method may also include determiningproperties of fluids produced from the portion as a function of time foreach set of heat source spacings. The produced fluids include, but arenot limited to, formation fluids such as pyrolyzation fluids andsynthesis gas. The determined properties may include, but are notlimited to, API gravity, carbon number distribution, olefin content,hydrogen content, carbon monoxide content, and/or carbon dioxidecontent. The determined set of properties of the produced fluid may becompared to a set of selected properties of a produced fluid. In thismanner, sets of properties that match the set of selected properties maybe determined. Furthermore, heat source spacings may be matched to heatsource spacings associated with desired properties.

[0382] Unit cell 404 will often include a number of heat sources 400disposed within a formation around each production well 402. An area ofunit cell 404 may be determined by midlines 406 that may be equidistantand perpendicular to a line connecting two production wells 402.Vertices 408 of the unit cell may be at the intersection of two midlines406 between production wells 402. Heat sources 400 may be disposed inany arrangement within the area of unit cell 404. For example, heatsources 400 may be located within the formation such that a distancebetween each heat source varies by less than approximately 10%, 20%, or30%. In addition, heat sources 400 may be disposed such that anapproximately equal space exists between each of the heat sources. Otherarrangements of heat sources 400 within unit cell 404, however, may beused depending on, for example, a heating rate of each of the heatsources. A ratio of heat sources 400 to production wells 402 may bedetermined by counting the number of heat sources 400 and productionwells 402 within unit cell 404, or over the total field.

[0383]FIG. 9 illustrates an embodiment of unit cell 404. Unit cell 404includes heat sources 400 and production wells 402. Unit cell 404 mayhave six full heat sources 400 a and six partial heat sources 400 b.Full heat sources 400 a may be closer to production well 402 thanpartial heat sources 400 b. In addition, an entirety of each of the fullheat sources 400 may be located within unit cell 404. Partial heatsources 400 b may be partially disposed within unit cell 404. Only aportion of heat source 400 b disposed within unit cell 404 may beconfigured to provide heat to a portion of a hydrocarbon containingformation disposed within unit cell 404. A remaining portion of heatsource 400 b disposed outside of unit cell 404 may be configured toprovide heat to a remaining portion of the hydrocarbon containingformation outside of unit cell 404. Therefore, to determine a number ofheat sources within unit cell 404 partial heat source 400 b may becounted as one-half of full heat sources 400. In other unit cellembodiments, fractions other than ½ (e.g. ⅓) may more accuratelydescribe the amount of heat applied to a portion from a partial heatsource.

[0384] The total number of heat sources 400 in unit cell 404 may includesix full heat sources 400 a that are each counted as one heat source,and six partial heat sources 400 b that are each counted as one half ofa heat source. Therefore, a ratio of heat sources 400 to productionwells 402 in unit cell 404 may be determined as 9:1. A ratio of heatsources to production wells may vary, however, depending on, forexample, the desired heating rate of the hydrocarbon containingformation, the heating rate of the heat sources, the type of heatsource, the type of hydrocarbon containing formation, the composition ofhydrocarbon containing formation, the desired composition of theproduced fluid, and/or the desired production rate. Providing more heatsources wells per unit area will allow faster heating of the selectedportion and thus hastening the onset of production, however more heatsources will generally cost more money to install. An appropriate ratioof heat sources to production wells may also include ratios greater thanabout 5:1, and ratios greater than about 7:1. In some embodiments anappropriate ratio of heat sources to production wells may be about 10:1,20:1, 50:1 or greater. If larger ratios are used, then project coststend to decrease since less wells and equipment are needed.

[0385] A “selected section” would generally be the volume of formationthat is within a perimeter defined by the location of the outermost heatsources (assuming that the formation is viewed from above). For example,if four heat sources were located in a single square pattern with anarea of about 100 m² (with each source located at a corner of thesquare), and if the formation had an average thickness of approximately5 m across this area, then the selected section would be a volume ofabout 500 m³ (i.e., the area multiplied by the average formationthickness across the area). In many commercial applications, it isenvisioned that many (e.g., hundreds or thousands) heat sources would beadjacent to each other to heat a selected section, and therefore in suchcases only the outermost (i.e., the “edge”) heat sources would definethe perimeter of the selected section.

[0386] A heat source may include, but is not limited to, an electricheater or a combustion heater. The electric heater may include aninsulated conductor, an elongated member disposed in the opening, and/ora conductor disposed in a conduit. Such an electric heater may beconfigured according to any of the embodiments described herein.

[0387] In an embodiment, a hydrocarbon containing formation may beheated with a natural distributed combustor system located in theformation. The generated heat may be allowed to transfer to a selectedsection of the formation to heat it.

[0388] A temperature sufficient to support oxidation may be, forexample, at least about 200° C. or 250° C. The temperature sufficient tosupport oxidation will tend to vary, however, depending on, for example,a composition of the hydrocarbons in the hydrocarbon containingformation, water content of the formation, and/or type and amount ofoxidant. Some water may be removed from the formation prior to heating.For example, the water may be pumped from the formation by dewateringwells. The heated portion of the formation may be near or substantiallyadjacent to an opening in the hydrocarbon containing formation. Theopening in the formation may be a heater well formed in the formation.The heater well may be formed as in any of the embodiments describedherein. The heated portion of the hydrocarbon containing formation mayextend radially from the opening to a width of about 0.3 m to about 1.2m. The width, however, may also be less than about 0.9 m. A width of theheated portion may vary. In certain embodiments the variance will dependon, for example, a width necessary to generate sufficient heat duringoxidation of carbon to maintain the oxidation reaction without providingheat from an additional heat source.

[0389] After the portion of the formation reaches a temperaturesufficient to support oxidation, an oxidizing fluid may be provided intothe opening to oxidize at least a portion of the hydrocarbons at areaction zone, or a heat source zone, within the formation. Oxidation ofthe hydrocarbons will generate heat at the reaction zone. The generatedheat will in most embodiments transfer from the reaction zone to apyrolysis zone in the formation. In certain embodiments the generatedheat will transfer at a rate between about 650 watts per meter asmeasured along a depth of the reaction zone, and/or 1650 watts per meteras measured along a depth of the reaction zone. Upon oxidation of atleast some of the hydrocarbons in the formation, energy supplied to theheater for initially heating may be reduced or may be turned off. Assuch, energy input costs may be significantly reduced, thereby providinga significantly more efficient system for heating the formation.

[0390] In an embodiment, a conduit may be disposed in the opening toprovide the oxidizing fluid into the opening. The conduit may have floworifices, or other flow control mechanisms (i.e., slits, venturi meters,valves, etc.) to allow the oxidizing fluid to enter the opening. Theterm “orifices” includes openings having a wide variety ofcross-sectional shapes including, but not limited to, circles, ovals,squares, rectangles, triangles, slits, or other regular or irregularshapes. The flow orifices may be critical flow orifices in someembodiments. The flow orifices may be configured to provide asubstantially constant flow of oxidizing fluid into the opening,regardless of the pressure in the opening.

[0391] In some embodiments, the number of flow orifices, which may beformed in or coupled to the conduit, may be limited by the diameter ofthe orifices and a desired spacing between orifices for a length of theconduit. For example, as the diameter of the orifices decreases, thenumber of flow orifices may increase, and vice versa. In addition, asthe desired spacing increases, the number of flow orifices may decrease,and vice versa. The diameter of the orifices may be determined by, forexample, a pressure in the conduit and/or a desired flow rate throughthe orifices. For example, for a flow rate of about 1.7 standard cubicmeters per minute and a pressure of about 7 bar absolute, an orificediameter may be about 1.3 mm with a spacing between orifices of about 2m.

[0392] Smaller diameter orifices may plug more easily than largerdiameter orifices due to, for example, contamination of fluid in theopening or solid deposition within or proximate to the orifices. In someembodiments, the number and diameter of the orifices can be chosen suchthat a more even or nearly uniform heating profile will be obtainedalong a depth of the formation within the opening. For example, a depthof a heated formation that is intended to have an approximately uniformheating profile may be greater than about 300 m, or even greater thanabout 600 m. Such a depth may vary, however, depending on, for example,a type of formation to be heated and/or a desired production rate.

[0393] In some embodiments, flow orifices may be disposed in a helicalpattern around the conduit within the opening. The flow orifices may bespaced by about 0.3 m to about 3 m between orifices in the helicalpattern. In some embodiments, the spacing may be about 1 m to about 2 mor, for example, about 1.5 m.

[0394] The flow of the oxidizing fluid into the opening may becontrolled such that a rate of oxidation at the reaction zone iscontrolled. Transfer of heat between incoming oxidant and outgoingoxidation products may heat the oxidizing fluid. The transfer of heatmay also maintain the conduit below a maximum operating temperature ofthe conduit.

[0395]FIG. 10 illustrates an embodiment of a natural distributedcombustor configured to heat a hydrocarbon containing formation. Conduit512 may be placed into opening 514 in formation 516. Conduit 512 mayhave inner conduit 513. Oxidizing fluid source 508 may provide oxidizingfluid 517 into inner conduit 513. Inner conduit 513 may have criticalflow orifices 515 along its length. Critical flow orifices 515 may bedisposed in a helical pattern (or any other pattern) along a length ofinner conduit 513 in opening 514. For example, critical flow orifices515 may be arranged in a helical pattern with a distance of about 1 m toabout 2.5 m between adjacent orifices. Critical flow orifices 515 may befurther configured as described herein. Inner conduit 513 may be sealedat the bottom. Oxidizing fluid 517 may be provided into opening 514through critical flow orifices 515 of inner conduit 513.

[0396] Critical flow orifices 515 may be designed such thatsubstantially the same flow rate of oxidizing fluid 517 may be providedthrough each critical flow orifice. Critical flow orifices 515 may alsoprovide substantially uniform flow of oxidizing fluid 517 along a lengthof conduit 512. Such flow may provide substantially uniform heating offormation 516 along the length of conduit 512.

[0397] Packing material 542 may enclose conduit 512 in overburden 540 ofthe formation. Packing material 542 may substantially inhibit flow offluids from opening 514 to surface 550. Packing material 542 may includeany material configurable to inhibit flow of fluids to surface 550 suchas cement, sand, and/or gravel. Typically a conduit or an opening in thepacking remains to provide a path for oxidation products to reach thesurface.

[0398] Oxidation products 519 typically enter conduit 512 from opening514. Oxidation products 519 may include carbon dioxide, oxides ofnitrogen, oxides of sulfur, carbon monoxide, and/or other productsresulting from a reaction of oxygen with hydrocarbons and/or carbon.Oxidation products 519 may be removed through conduit 512 to surface550. Oxidation product 519 may flow along a face of reaction zone 524 inopening 514 until proximate an upper end of opening 514 where oxidationproduct 519 may flow into conduit 512. Oxidation products 519 may alsobe removed through one or more conduits disposed in opening 514 and/orin formation 516. For example, oxidation products 519 may be removedthrough a second conduit disposed in opening 514. Removing oxidationproducts 519 through a conduit may substantially inhibit oxidationproducts 519 from flowing to a production well disposed in formation516. Critical flow orifices 515 may also be configured to substantiallyinhibit oxidation products 519 from entering inner conduit 513.

[0399] A flow rate of oxidation product 519 may be balanced with a flowrate of oxidizing fluid 517 such that a substantially constant pressureis maintained within opening 514. For a 100 m length of heated section,a flow rate of oxidizing fluid may be between about 0.5 standard cubicmeters per minute to about 5 standard cubic meters per minute, or about1.0 standard cubic meters per minute to about 4.0 standard cubic metersper minute, or, for example, about 1.7 standard cubic meters per minute.A flow rate of oxidizing fluid into the formation may be incrementallyincreased during use to accommodate expansion of the reaction zone. Apressure in the opening may be, for example, about 8 bar absolute.Oxidizing fluid 517 may oxidize at least a portion of the hydrocarbonsin heated portion 518 of hydrocarbon containing formation 516 atreaction zone 524. Heated portion 518 may have been initially heated toa temperature sufficient to support oxidation by an electric heater, asshown in FIG. 14, or by any other suitable system or method describedherein. In some embodiments, an electric heater may be placed inside orstrapped to the outside of conduit 513.

[0400] In certain embodiments it is beneficial to control the pressurewithin the opening 514 such that oxidation product and/or oxidationfluids are inhibited from flowing into the pyrolysis zone of theformation. In some instances pressure within opening 514 will bebalanced with pressure within the formation to do so.

[0401] Although the heat from the oxidation is transferred to theformation, oxidation product 519 (and excess oxidation fluid such asair) may be substantially inhibited from flowing through the formationand/or to a production well within formation 516. Instead oxidationproduct 519 (and excess oxidation fluid) is removed (e.g., through aconduit such as conduit 512) as is described herein. In this manner,heat is transferred to the formation from the oxidation but exposure ofthe pyrolysis zone with oxidation product 519 and/or oxidation fluid maybe substantially inhibited and/or prevented.

[0402] In certain embodiments, some pyrolysis product near the reactionzone 524 may also be oxidized in reaction zone 524 in addition to thecarbon. Oxidation of the pyrolysis product in reaction zone 524 mayprovide additional heating of formation 516. When such oxidation ofpyrolysis product occurs, it is desirable that oxidation product fromsuch oxidation be removed (e.g., through a conduit such as conduit 512)near the reaction zone as is described herein, thereby inhibitingcontamination of other pyrolysis product in the formation with oxidationproduct.

[0403] Conduit 512 may be configured to remove oxidation product 519from opening 514 in formation 516. As such, oxidizing fluid 517 in innerconduit 513 may be heated by heat exchange in overburden section 540from oxidation product 519 in conduit 512. Oxidation product 519 may becooled by transferring heat to oxidizing fluid 517. In this manner,oxidation of hydrocarbons within formation 516 may be more thermallyefficient.

[0404] Oxidizing fluid 517 may transport through reaction zone 524, orheat source zone, by gas phase diffusion and/or convection. Diffusion ofoxidizing fluid 517 through reaction zone 524 may be more efficient atthe relatively high temperatures of oxidation. Diffusion of oxidizingfluid 517 may inhibit development of localized overheating and fingeringin the formation. Diffusion of oxidizing fluid 517 through formation 516is generally a mass transfer process. In the absence of an externalforce, a rate of diffusion for oxidizing fluid 517 may depend uponconcentration, pressure, and/or temperature of oxidizing fluid 517within formation 516. The rate of diffusion may also depend upon thediffusion coefficient of oxidizing fluid 517 through formation 516. Thediffusion coefficient may be determined by measurement or calculationbased on the kinetic theory of gases. In general, random motion ofoxidizing fluid 517 may transfer oxidizing fluid 517 through formation516 from a region of high concentration to a region of lowconcentration.

[0405] With time, reaction zone 524 may slowly extend radially togreater diameters from opening 514 as hydrocarbons are oxidized.Reaction zone 524 may, in many embodiments, maintain a relativelyconstant width. For example, reaction zone 524 may extend radially at arate of less than about 0.91 m per year for a hydrocarbon containingformation. For example, for a coal containing formation, reaction zone524 may extend radially at a rate between about 0.5 m per year to about1 m per year. For an oil shale containing formation, reaction zone 524may extend radially about 2 m in the first year and at a lower rate insubsequent years due to an increase in volume of reaction zone 524 asreaction zone 524 extends radially. Such a lower rate may be about 1 mper year to about 1.5 m per year. Reaction zone 524 may extend at slowerrates for hydrocarbon rich formations (e.g., coal) and at faster ratesfor formations with more inorganic material in it (e.g., oil shale)since more hydrocarbons per volume are available for combustion in thehydrocarbon rich formations.

[0406] A flow rate of oxidizing fluid 517 into opening 514 may beincreased as a diameter of reaction zone 524 increases to maintain therate of oxidation per unit volume at a substantially steady state. Thus,a temperature within reaction zone 524 may be maintained substantiallyconstant in some embodiments. The temperature within reaction zone 524may be between about 650° C. to about 900° C. or, for example, about760° C. The temperature may be maintained below a temperature thatresults in production of oxides of nitrogen (NO_(x)).

[0407] The temperature within reaction zone 524 may vary depending on,for example, a desired heating rate of selected section 526. Thetemperature within reaction zone 524 may be increased or decreased byincreasing or decreasing, respectively, a flow rate of oxidizing fluid517 into opening 514. A temperature of conduit 512, inner conduit 513,and/or any metallurgical materials within opening 514 typically will notexceed a maximum operating temperature of the material. Maintaining thetemperature below the maximum operating temperature of a material mayinhibit excessive deformation and/or corrosion of the material.

[0408] An increase in the diameter of reaction zone 524 may allow forrelatively rapid heating of the hydrocarbon containing formation 516. Asthe diameter of reaction zone 524 increases, an amount of heat generatedper time in reaction zone 524 may also increase. Increasing an amount ofheat generated per time in the reaction zone will in many instancesincrease heating rate of the formation 516 over a period of time, evenwithout increasing the temperature in the reaction zone or thetemperature at conduit 513. Thus, increased heating may be achieved overtime without installing additional heat sources, and without increasingtemperatures adjacent to wellbores. In some embodiments the heatingrates may be increased while allowing the temperatures to decrease(allowing temperatures to decrease may often lengthen the life of theequipment used).

[0409] By utilizing the carbon in the formation as a fuel, the naturaldistributed combustor may save significantly on energy costs. Thus, aneconomical process may be provided for heating formations that mayotherwise be economically unsuitable for heating by other methods. Also,fewer heaters may be placed over an extended area of formation 516. Thismay provide for a reduced equipment cost associated with heating theformation 516.

[0410] The heat generated at reaction zone 524 may transfer by thermalconduction to selected section 526 of formation 516. In addition,generated heat may transfer from a reaction zone to the selected sectionto a lesser extent by convection heat transfer. Selected section 526,sometimes referred to herein as the “pyrolysis zone,” may besubstantially adjacent to reaction zone 524. Since oxidation product(and excess oxidation fluid such as air) is typically removed from thereaction zone, the pyrolysis zone can receive heat from the reactionzone without being exposed to oxidation product, or oxidants, that arein the reaction zone. Oxidation product and/or oxidation fluids maycause the formation of undesirable formation products if they arepresent in the pyrolysis zone. For example, in certain embodiments it isdesirable to conduct pyrolysis in a reducing environment. Thus, it isoften useful to allow heat to transfer from the reaction zone to thepyrolysis zone while inhibiting or preventing oxidation product and/oroxidation fluid from reaching the pyrolysis zone.

[0411] Pyrolysis of hydrocarbons, or other heat-controlled processes,may take place in heated selected section 526. Selected section 526 maybe at a temperature between about 270° C. to about 400° C. forpyrolysis. The temperature of selected section 526 may be increased byheat transfer from reaction zone 524. A rate of temperature increase maybe selected as in any of the embodiments described herein. A temperaturein formation 516, selected section 526, and/or reaction zone 524 may becontrolled such that production of oxides of nitrogen may besubstantially inhibited. Oxides of nitrogen are often produced attemperatures above about 1200° C.

[0412] A temperature within opening 514 may be monitored with athermocouple disposed in opening 514. Alternatively, a thermocouple maybe disposed on conduit 512 and/or disposed on a face of reaction zone524, and a temperature may be monitored accordingly. The temperature inthe formation may be monitored by the thermocouple, and power input oroxidant introduced into the formation may be controlled based upon themonitored temperature such that the monitored temperature is maintainedwithin a selected range. The selected range may vary, depending on, forexample, a desired heating rate of formation 516. In an embodiment,monitored temperature is maintained within a selected range byincreasing or decreasing a flow rate of oxidizing fluid 517. Forexample, if a temperature within opening 514 falls below a selectedrange of temperatures, the flow rate of oxidizing fluid 517 is increasedto increase the combustion and thereby increase the temperature withinopening 514.

[0413] In certain embodiments one or more natural distributed combustorsmay be placed along strike and/or horizontally. Doing so tends to reducepressure differentials along the heated length of the well. The absenceof pressure differentials may make controlling the temperature generatedalong a length of the heater more uniform and more easy to control.

[0414] In some embodiments, a presence of air or oxygen (O₂) inoxidation product 519 may be monitored. Alternatively, an amount ofnitrogen, carbon monoxide, carbon dioxide, oxides of nitrogen, oxides ofsulfur, etc. may be monitored in oxidation product 519. Monitoring thecomposition and/or quantity of oxidation product 519 may be useful forheat balances, for process diagnostics, process control, etc.

[0415]FIG. 11 illustrates an embodiment of a section of overburden witha natural distributed combustor as described in FIG. 10. Overburdencasing 541 may be disposed in overburden 540 of formation 516.Overburden casing 541 may be substantially surrounded by materials(e.g., an insulating material such as cement) that may substantiallyinhibit heating of overburden 540. Overburden casing 541 may be made ofa metal material such as, but not limited to, carbon steel, or 304stainless steel.

[0416] Overburden casing may be placed in reinforcing material 544 inoverburden 540. Reinforcing material 544 may be, for example, cement,sand, concrete, etc. Packing material 542 may be disposed betweenoverburden casing 541 and opening 514 in the formation. Packing material542 may be any substantially non-porous material (e.g., cement,concrete, grout, etc.). Packing material 542 may inhibit flow of fluidoutside of conduit 512 and between opening 514 and surface 550. Innerconduit 513 may provide a fluid into opening 514 in formation 516.Conduit 512 may remove a combustion product (or excess oxidation fluid)from opening 514 in formation 516. Diameter of conduit 512 may bedetermined by an amount of the combustion product produced by oxidationin the natural distributed combustor. For example, a larger diameter maybe required for a greater amount of exhaust product produced by thenatural distributed combustor heater.

[0417] In an alternative embodiment, at least a portion of the formationmay be heated to a temperature such that at least a portion of thehydrocarbon containing formation may be converted to coke and/or char.Coke and/or char may be formed at temperatures above about 400° C. andat a high heating rate (e.g., above about 10° C./day). In the presenceof an oxidizing fluid, the coke or char will oxidize. Heat may begenerated from the oxidation of coke or char as in any of theembodiments described herein.

[0418]FIG. 12 illustrates an embodiment of a natural distributedcombustor heater. Insulated conductor 562 may be coupled to conduit 532and placed in opening 514 in formation 516. Insulated conductor 562 maybe disposed internal to conduit 532 (thereby allowing retrieval of theinsulated conductor 562), or, alternately, coupled to an externalsurface of conduit 532. Such insulating material may include, forexample, minerals, ceramics, etc. Conduit 532 may have critical floworifices 515 disposed along its length within opening 514. Critical floworifices 515 may be configured as described herein. Electrical currentmay be applied to insulated conductor 562 to generate radiant heat inopening 514. Conduit 532 may be configured to serve as a return forcurrent. Insulated conductor 562 may be configured to heat portion 518of the formation to a temperature sufficient to support oxidation ofhydrocarbons. Portion 518, reaction zone 524, and selected section 526may have characteristics as described herein. Such a temperature mayinclude temperatures as described herein.

[0419] Oxidizing fluid source 508 may provide oxidizing fluid intoconduit 532. Oxidizing fluid may be provided into opening 514 throughcritical flow orifices 515 in conduit 532. Oxidizing fluid may oxidizeat least a portion of the hydrocarbon containing formation in reactionzone 524. Reaction zone 524 may have characteristics as describedherein. Heat generated at reaction zone 524 may transfer heat toselected section 526, for example, by convection, radiation, and/orconduction. Oxidation product may be removed through a separate conduitplaced in opening 514 or through an opening 543 in overburden casing541. The separate conduit may be configured as described herein. Packingmaterial 542 and reinforcing material 544 may be configured as describedherein.

[0420]FIG. 13 illustrates an embodiment of a natural distributedcombustor heater with an added fuel conduit. Fuel conduit 536 may bedisposed into opening 514. It may be disposed substantially adjacent toconduit 533 in certain embodiments. Fuel conduit 536 may have criticalflow orifices 535 along its length within opening 514. Conduit 533 mayhave critical flow orifices 515 along its length within opening 514.Critical flow orifices 515 may be configured as described herein.Critical flow orifices 535 and critical flow orifices 515 may be placedon fuel conduit 536 and conduit 533, respectively, such that a fuelfluid provided through fuel conduit 536 and an oxidizing fluid providedthrough conduit 533 may not substantially heat fuel conduit 536 and/orconduit 533 upon reaction. For example, the fuel fluid and the oxidizingfluid may react upon contact with each other, thereby producing heatfrom the reaction. The heat from this reaction may heat fuel conduit 536and/or conduit 533 to a temperature sufficient to substantially beginmelting metallurgical materials in fuel conduit 536 and/or conduit 533if the reaction takes place proximate to fuel conduit 536 and/or conduit533. Therefore, a design for disposing critical flow orifices 535 onfuel conduit 536 and critical flow orifices 515 on conduit 533 may beprovided such that the fuel fluid and the oxidizing fluid may notsubstantially react proximate to the conduits. For example, conduits 536and 533 may be spatially coupled together such that orifices that spiralaround the conduits are oriented in opposite directions.

[0421] Reaction of the fuel fluid and the oxidizing fluid may produceheat. The fuel fluid may be, for example, natural gas, ethane, hydrogenor synthesis gas that is generated in the in situ process in anotherpart of the formation. The produced heat may be configured to heatportion 518 to a temperature sufficient to support oxidation ofhydrocarbons. Upon heating of portion 518 to a temperature sufficient tosupport oxidation, a flow of fuel fluid into opening 514 may be turneddown or may be turned off. Alternatively, the supply of fuel may becontinued throughout the heating of the formation, thereby utilizing thestored heat in the carbon to maintain the temperature in opening 514above the autoignition temperature of the fuel.

[0422] The oxidizing fluid may oxidize at least a portion of thehydrocarbons at reaction zone 524. Generated heat will transfer heat toselected section 526, for example, by radiation, convection, and/orconduction. An oxidation product may be removed through a separateconduit placed in opening 514 or through an opening 543 in overburdencasing 541.

[0423]FIG. 14 illustrates an embodiment of a system configured to heat ahydrocarbon containing formation. Electric heater 510 may be disposedwithin opening 514 in hydrocarbon containing formation 516. Opening 514may be formed through overburden 540 into formation 516. Opening 514 maybe at least about 5 cm in diameter. Opening 514 may, as an example, havea diameter of about 13 cm. Electric heater 510 may heat at least portion518 of hydrocarbon containing formation 516 to a temperature sufficientto support oxidation (e.g., about 260° C.). Portion 518 may have a widthof about 1 m. An oxidizing fluid (e.g., liquid or gas) may be providedinto the opening through conduit 512 or any other appropriate fluidtransfer mechanism. Conduit 512 may have critical flow orifices 515disposed along a length of the conduit. Critical flow orifices 515 maybe configured as described herein.

[0424] For example, conduit 512 may be a pipe or tube configured toprovide the oxidizing fluid into opening 514 from oxidizing fluid source508. For example, conduit 512 may be a stainless steel tube. Theoxidizing fluid may include air or any other oxygen containing fluid(e.g., hydrogen peroxide, oxides of nitrogen, ozone). Mixtures ofoxidizing fluids may be used. An oxidizing fluid mixture may include,for example, a fluid including fifty percent oxygen and fifty percentnitrogen. The oxidizing fluid may also, in some embodiments, includecompounds that release oxygen when heated such as hydrogen peroxide. Theoxidizing fluid may oxidize at least a portion of the hydrocarbons inthe formation.

[0425] In some embodiments, a heat exchanger disposed external to theformation may be configured to heat the oxidizing fluid. The heatedoxidizing fluid may be provided into the opening from (directly orindirectly) the heat exchanger. For example, the heated oxidizing fluidmay be provided from the heat exchanger into the opening through aconduit disposed in the opening and coupled to the heat exchanger. Insome embodiments the conduit may be a stainless steel tube. The heatedoxidizing fluid may be configured to heat, or at least contribute to theheating of, at least a portion of the formation to a temperaturesufficient to support oxidation of hydrocarbons. After the heatedportion reaches such a temperature, heating of the oxidizing fluid inthe heat exchanger may be reduced or may be turned off.

[0426]FIG. 15 illustrates another embodiment of a system configured toheat a hydrocarbon containing formation. Heat exchanger 520 may bedisposed external to opening 514 in hydrocarbon containing formation516. Opening 514 may be formed through overburden 540 into formation516. Heat exchanger 520 may provide heat from another surface process,or it may include a heater (e.g., an electric or combustion heater).Oxidizing fluid source 508 may provide an oxidizing fluid to heatexchanger 520. Heat exchanger 520 may heat an oxidizing fluid (e.g.,above 200° C or a temperature sufficient to support oxidation ofhydrocarbons). The heated oxidizing fluid may be provided into opening514 through conduit 521. Conduit 521 may have critical flow orifices 515disposed along a length of the conduit. Critical flow orifices 515 maybe configured as described, herein. The heated oxidizing fluid may heat,or at least contribute to the heating of, at least portion 518 of theformation to a temperature sufficient to support oxidation ofhydrocarbons. The oxidizing fluid may oxidize at least a portion of thehydrocarbons in the formation.

[0427] In another embodiment, a fuel fluid may be oxidized in a heaterlocated external to a hydrocarbon containing formation. The fuel fluidmay be oxidized with an oxidizing fluid in the heater. As an example,the heater may be a flame-ignited heater. A fuel fluid may include anyfluid configured to react with oxygen. Fuel fluids may be, but are notlimited to, methane, ethane, propane, other hydrocarbons, hydrogen,synthesis gas, or combinations thereof. The oxidized fuel fluid may beprovided into the opening from the heater through a conduit andoxidation products and unreacted fuel may return to the surface throughanother conduit in the overburden. The conduits may be coupled withinthe overburden. In some embodiments, the conduits may be concentricallyplaced. The oxidized fuel fluid may be configured to heat, or at leastcontribute to the heating of, at least a portion of the formation to atemperature sufficient to support oxidation of hydrocarbons. Uponreaching such a temperature, the oxidized fuel fluid may be replacedwith an oxidizing fluid. The oxidizing fluid may oxidize at least aportion of the hydrocarbons at a reaction zone within the formation.

[0428] An electric heater may be configured to heat a portion of thehydrocarbon containing formation to a temperature sufficient to supportoxidation of hydrocarbons. The portion may be proximate to orsubstantially adjacent to the opening in the formation. The portion mayalso radially extend a width of less than approximately 1 m from theopening. A width of the portion may vary, however, depending on, forexample, a power supplied to the heater. An oxidizing fluid may beprovided to the opening for oxidation of hydrocarbons. Oxidation of thehydrocarbons may be configured to heat the hydrocarbon containingformation in a process of natural distributed combustion. Electricalcurrent applied to the electric heater may subsequently be reduced ormay be turned off. Thus, natural distributed combustion may beconfigured, in conjunction with an electric heater, to provide a reducedinput energy cost method to heat the hydrocarbon containing formationcompared to using an electric heater.

[0429] An insulated conductor heater may be a heater element of a heatsource. In an embodiment of an insulated conductor heater, the insulatedconductor heater is a mineral insulated cable or rod. An insulatedconductor heater may be placed in an opening in a hydrocarbon containingformation. The insulated conductor heater may be placed in an uncasedopening in the hydrocarbon containing formation. Placing the heater inan uncased opening in the hydrocarbon containing formation may allowheat transfer from the heater to the formation by radiation, as well as,conduction. In addition, using an uncased opening may also allowretrieval of the heater from the well, if necessary, and may eliminatethe cost of the casing. Alternately, the insulated conductor heater maybe placed within a casing in the formation; may be cemented within theformation; or may be packed in an opening with sand, gravel, or otherfill material. The insulated conductor heater may be supported on asupport member positioned within the opening. The support member may bea cable, rod, or a conduit (e.g., a pipe). The support member may bemade of a metal, ceramic, inorganic material, or combinations thereof.Portions of a support member may be exposed to formation fluids and heatduring use, so the support member may be chemically resistant andthermally resistant.

[0430] Ties, spot welds and/or other types of connectors may be used tocouple the insulated conductor heater to the support member at variouslocations along a length of the insulated conductor heater. The supportmember may be attached to a wellhead at an upper surface of theformation. In an alternate embodiment of an insulated conductor heater,the insulated conductor heater is designed to have sufficient structuralstrength so that a support member is not needed. The insulated conductorheater will in many instances have some flexibility to inhibit thermalexpansion damage when heated or cooled.

[0431] In certain embodiments, insulated conductor heaters may be placedin wellbores without support members and/or centralizers. This can beaccomplished for heaters if the insulated conductor has a suitablecombination of temperature and corrosion resistance, creep strength,length, thickness (diameter), and metallurgy that will inhibit failureof the insulated conductor during use. In an embodiment, insulatedconductors that are heated to working temperature of about 700° C. areless than about 150 meters in length, are made of 310 stainless steel,and may be used without support members.

[0432]FIG. 16 depicts a perspective view of an end portion of anembodiment of an insulated conductor heater 562. An insulated conductorheater may have any desired cross sectional shape, such as, but notlimited to round (as shown in FIG. 16), triangular, ellipsoidal,rectangular, hexagonal or irregular shape. An insulated conductor heatermay include conductor 575, electrical insulation 576 and sheath 577. Theconductor 575 may resistively heat when an electrical current passesthrough the conductor. An alternating or direct current may be used toheat the conductor 575. In an embodiment, a 60 cycle AC current may beused.

[0433] In some embodiments, the electrical insulation 576 may inhibitcurrent leakage and may inhibit arcing to the sheath 577. The electricalinsulation 576 may also thermally conduct heat generated in theconductor 575 to the sheath 577. The sheath 577 may radiate or conductheat to the formation. An insulated conductor heater 562 may be 1000 mor more in length. In an embodiment of an insulated conductor heater,the insulated conductor heater 562 may have a length from about 15 m toabout 950 m. Longer or shorter insulated conductors may also be used tomeet specific application needs. In embodiments of insulated conductorheaters, purchased insulated conductor heaters have lengths of about 100m to 500 m (e.g., 230 m). In certain embodiments, dimensions of sheathsand/or conductors of an insulated conductor may be formed so that theinsulated conductors have enough strength to be self supporting even atupper working temperatures. Such insulated cables may be suspended fromwellheads or supports positioned near an interface between an overburdenand a hydrocarbon containing formation without the need for supportmembers extending into the hydrocarbon formation along with theinsulated conductors.

[0434] In an embodiment, a higher frequency current may be used to takeadvantage of the skin effect in certain metals. In some embodiments, a60 cycle AC current may be used in combination with conductors made ofmetals that exhibit pronounced skin effects. For example, ferromagneticmetals like iron alloys and nickel may exhibit a skin effect. The skineffect confines the current to a region close to the outer surface ofthe conductor, thereby effectively increasing the resistance of theconductor. A higher resistance may be desired to decrease the operatingcurrent, minimize ohmic losses in surface cables, and also minimize thecost of surface facilities.

[0435] As illustrated in FIG. 17, an insulated conductor heater 562 willin many instances be designed to operate at a power level of up to about1650 watts/meter. The insulated conductor heater 562 may typicallyoperate at a power level between about 500 watts/meter and about 1150watts/meter when heating a formation. The insulated conductor heater 562may be designed so that a maximum voltage level at a typical operatingtemperature does not cause substantial thermal and/or electricalbreakdown of electrical insulation 576. The insulated conductor heater562 may be designed so that the sheath 577 does not exceed a temperaturethat will result in a significant reduction in corrosion resistanceproperties of the sheath material.

[0436] In an embodiment of an insulated conductor heater 562, theconductor 575 may be designed to reach temperatures within a rangebetween about 650° C. to about 870° C., and the sheath 577 may bedesigned to reach temperatures within a range between about 535° C. toabout 760° C. Insulated conductors having other operating ranges may beformed to meet specific operational requirements. In an embodiment of aninsulated conductor heater 562, the conductor 575 is designed to operateat about 760° C., the sheath 577 is designed to operate at about 650°C., and the insulated conductor heater is designed to dissipate about820 watts/meter.

[0437] An insulated conductor heater 562 may have one or more conductors575. For example, a single insulated conductor heater may have threeconductors within electrical insulation that are surrounded by a sheath.FIG. 16 depicts an insulated conductor heater 562 having a singleconductor 575. The conductor may be made of metal. The material used toform a conductor may be, but is not limited to, nichrome, nickel, and anumber of alloys made from copper and nickel in increasing nickelconcentrations from pure copper to Alloy 30, Alloy 60, Alloy 180 andMonel. Alloys of copper and nickel may advantageously have betterelectrical resistance properties than substantially pure nickel orcopper.

[0438] In an embodiment, the conductor may be chosen to have a diameterand a resistivity at operating temperatures such that its resistance, asderived from Ohm's law, makes it electrically and structurally stablefor the chosen power dissipation per meter, the length of the heater,and/or the maximum voltage allowed to pass through the conductor. In analternate embodiment, the conductor may be designed, using Maxwell'sequations, to make use of skin effect heating in and/or on theconductor.

[0439] The conductor may be made of different material along a length ofthe insulated conductor heater. For example, a first section of theconductor may be made of a material that has a significantly lowerresistance than a second section of the conductor. The first section maybe placed adjacent to a formation layer that does not need to be heatedto as high a temperature as a second formation layer that is adjacent tothe second section. The resistivity of various sections of conductor maybe adjusted by having a variable diameter and/or by having conductorsections made of different materials.

[0440] A diameter of a conductor 575 may typically be between about 1.3mm to about 10.2 mm. Smaller or larger diameters may also be used tohave conductors with desired resistivity characteristics. In anembodiment of an insulated conductor heater, the conductor is made ofAlloy 60 that has a diameter of about 5.8 mm.

[0441] As illustrated in FIG. 16, an electrical insulator 576 of aninsulated conductor heater 562 may be made of a variety of materials.Pressure may be used to place electrical insulator powder between aconductor 575 and a sheath 577. Low flow characteristics and otherproperties of the powder and/or the sheaths and conductors may inhibitthe powder from flowing out of the sheaths. Commonly used powders mayinclude, but are not limited to, MgO, Al₂O₃, Zirconia, BeO, differentchemical variations of Spinels, and combinations thereof. MgO mayprovide good thermal conductivity and electrical insulation properties.The desired electrical insulation properties include low leakage currentand high dielectric strength. A low leakage current decreases thepossibility of thermal breakdown and the high dielectric strengthdecreases the possibility of arcing across the insulator. Thermalbreakdown can occur if the leakage current causes a progressive rise inthe temperature of the insulator leading also to arcing across theinsulator. An amount of impurities 578 in the electrical insulatorpowder may be tailored to provide required dielectric strength and a lowlevel of leakage current. The impurities 578 added may be, but are notlimited to, CaO, Fe₂O₃, Al₂O₃, and other metal oxides. Low porosity ofthe electrical insulation tends to reduce leakage current and increasedielectric strength. Low porosity may be achieved by increased packingof the MgO powder during fabrication or by filling of the pore space inthe MgO powder with other granular materials, for example, Al₂O₃.

[0442] The impurities 578 added to the electrical insulator powder mayhave particle sizes that are smaller than the particle sizes of thepowdered electrical insulator. The small particles may occupy pore spacebetween the larger particles of the electrical insulator so that theporosity of the electrical insulator is reduced. Examples of powderedelectrical insulators that may be used to form electrical insulation 576are “H” mix manufactured by Idaho Laboratories Corporation (Idaho Falls,Id.), or Standard MgO used by Pyrotenax Cable Company (Trenton, Ontario)for high temperature applications. In addition, other powderedelectrical insulators may be used.

[0443] A sheath 577 of an insulated conductor heater 562 may be an outermetallic layer. The sheath 577 may be in contact with hot formationfluids. The sheath 577 may need to be made of a material having a highresistance to corrosion at elevated temperatures. Alloys that may beused in a desired operating temperature range of the sheath include, butare not limited to, 304 stainless steel, 310 stainless steel, Incoloy800, and Inconel 600. The thickness of the sheath has to be sufficientto last for three to ten years in a hot and corrosive environment. Athickness of the sheath may generally vary between about 1 mm and about2.5 mm. For example, a 1.3 mm thick 310 stainless steel outer layerprovides a sheath 577 that is able to provide good chemical resistanceto sulfidation corrosion in a heated zone of a formation for a period ofover 3 years. Larger or smaller sheath thicknesses may be used to meetspecific application requirements.

[0444] An insulated conductor heater may be tested after fabrication.The insulated conductor heater may be required to withstand 2-3 times anoperating voltage at a selected operating temperature. Also, selectedsamples of produced insulated conductor heaters may be required towithstand 1000 VAC at 760° C. for one month.

[0445] As illustrated in FIG. 17a, a short flexible transition conductor571 may be connected to a lead-in conductor 572 using a connection 569made during heater installation in the field. The transition conductor571 may, for example, be a flexible, low resistivity, stranded coppercable that is surrounded by rubber or polymer insulation. A transitionconductor 571 may typically be between about 1.5 m and about 3 m,although longer or shorter transition conductors may be used toaccommodate particular needs. Temperature resistant cable may be used astransition conductor 571. The transition conductor 571 may also beconnected to a short length of an insulated conductor heater that isless resistive than a primary heating section of the insulated conductorheater. The less resistive portion of the insulated conductor heater maybe referred to as a “cold pin” 568.

[0446] A cold pin 568 may be designed to dissipate about one tenth toabout one fifth of the power per unit length as is dissipated in a unitlength of the primary heating section. Cold pins may typically bebetween about 1.5 m to about 15 m, although shorter or longer lengthsmay be used to accommodate specific application needs. In an embodiment,the conductor of a cold pin section is copper with a diameter of about6.9 mm and a length of 9.1 m. The electrical insulation is the same typeof insulation used in the primary heating section. A sheath of the coldpin may be made of Inconel 600. Chloride corrosion cracking in the coldpin region may occur, so a chloride corrosion resistant metal such asInconel 600 may be used as the sheath.

[0447] As illustrated in FIG. 17a, a small, epoxy filled canister 573may be used to create a connection between a transition conductor 571and a cold pin 568. Cold pins 568 may be connected to the primaryheating sections of insulated conductor 562 heaters by “splices” 567.The length of the cold pin 568 may be sufficient to significantly reducea temperature of the insulated conductor heater 562. The heater sectionof the insulated conductor heater 562 may operate from about 530° C. toabout 760° C., the splice 567 may be at a temperature from about 260° C.to about 370° C., and the temperature at the lead-in cable connection tothe cold pin may be from about 40° C. to about 90° C. In addition to acold pin at a top end of the insulated conductor heater, a cold pin mayalso be placed at a bottom end of the insulated conductor heater. Thecold pin at the bottom end may in many instances make a bottomtermination easier to manufacture.

[0448] Splice material may have to withstand a temperature equal to halfof a target zone operating temperature. Density of electrical insulationin the splice should in many instances be high enough to withstand therequired temperature and the operating voltage.

[0449] A splice 567 may be required to withstand 1000 VAC at 480° C.Splice material may be high temperature splices made by IdahoLaboratories Corporation or by Pyrotenax Cable Company. A splice may bean internal type of splice or an external splice. An internal splice istypically made without welds on the sheath of the insulated conductorheater. The lack of weld on the sheath may avoid potential weak spots(mechanical and/or electrical) on the insulated cable heater. Anexternal splice is a weld made to couple sheaths of two insulatedconductor heaters together. An external splice may need to be leaktested prior to insertion of the insulated cable heater into aformation. Laser welds or orbital TIG (tungsten inert gas) welds may beused to form external splices. An additional strain relief assembly maybe placed around an external splice to improve the splice's resistanceto bending and to protect the external splice against partial or totalparting.

[0450] An insulated conductor assembly may include heating sections,cold pins, splices, and termination canisters and flexible transitionconductors. The insulated conductor assembly may need to be examined andelectrically tested before installation of the assembly into an openingin a formation. The assembly may need to be examined for competent weldsand to make sure that there are no holes in the sheath anywhere alongthe whole heater (including the heated section, the cold-pins, thesplices and the termination cans). Periodic X-ray spot checking of thecommercial product may need to be made. The whole cable may be immersedin water prior to electrical testing. Electrical testing of the assemblymay need to show more than 2000 megaohms at 500 VAC at room temperatureafter water immersion. In addition, the assembly may need to beconnected to 1000 VAC and show less than about 10 microamps per meter ofresistive leakage current at room temperature. Also, a check on leakagecurrent at about 760° C. may need to show less than about 0.4 milliampsper meter.

[0451] There are a number of companies that manufacture insulatedconductor heaters. Such manufacturers include, but are not limited to,MI Cable Technologies (Calgary, Alberta), Pyrotenax Cable Company(Trenton, Ontario), Idaho Laboratories Corporation (Idaho Falls, Id.),and Watlow (St. Louis, Mo.). As an example, an insulated conductorheater may be ordered from Idaho Laboratories as cable model355-A90-310-“H” 30′/750′/30′ with Inconel 600 sheath for the cold-pins,three phase Y configuration and bottom jointed conductors. The requiredspecification for the heater should also include 1000 VAC, 1400° F.quality cable in addition to the preferred mode specifications describedabove. The designator 355 specifies the cable OD (0.355″), A90 specifiesthe conductor material, 310 specifies the heated zone sheath alloy (SS310), “H” specifies the MgO mix, 30′/750′/30′ specifies about a 230 mheated zone with cold-pins top and bottom having about 9 m lengths. Asimilar part number with the same specification using high temperatureStandard purity MgO cable may be ordered from Pyrotenax Cable Company.

[0452] One or more insulated conductor heaters may be placed within anopening in a formation to form a heat source or heat sources. Electricalcurrent may be passed through each insulated conductor heater in theopening to heat the formation. Alternately, electrical current may bepassed through selected insulated conductor heaters in an opening. Theunused conductors may be backup heaters. Insulated conductor heaters maybe electrically coupled to a power source in any convenient manner. Eachend of an insulated conductor heater may be coupled to lead-in cablesthat pass through a wellhead. Such a configuration typically has a 180°bend (a “hairpin” bend) or turn located near a bottom of the heatsource. An insulated conductor heater that includes a 180° bend or turnmay not require a bottom termination, but the 180° bend or turn may bean electrical and/or structural weakness in the heater. Insulatedconductor heaters may be electrically coupled together in series, inparallel, or in series and parallel combinations. In some embodiments ofheat sources, electrical current may pass into the conductor of aninsulated conductor heater and may returned through the sheath of theinsulated conductor heater by connecting the conductor 575 to the sheath577 at the bottom of the heat source.

[0453] In an embodiment of a heat source depicted in FIG. 17, threeinsulated conductor heaters 562 are electrically coupled in a 3-phase Yconfiguration to a power supply. The power supply may provide a 60 cycleAC current to the electrical conductors. No bottom connection may berequired for the insulated conductor heaters. Alternately, all threeconductors of the three phase circuit may be connected together near thebottom of a heat source opening. The connection may be made directly atends of heating sections of the insulated conductor heaters or at endsof cold pins coupled to the heating sections at the bottom of theinsulated conductor heaters. The bottom connections may be made withinsulator filled and sealed canisters or with epoxy filled canisters.The insulator may be the same composition as the insulator used as theelectrical insulation.

[0454] The three insulated conductor heaters depicted in FIG. 17 may becoupled to support member 564 using centralizers 566. Alternatively, thethree insulated conductor heaters may be strapped directly to thesupport tube using metal straps. Centralizers 566 may be configured tomaintain a location of insulated conductor heaters 562 on support member564. Centralizers 566 may be made of, for example, metal, ceramic or acombination thereof. The metal may be stainless steel or any other typeof metal able to withstand a corrosive and hot environment. In someembodiments, centralizers 566 may be simple bowed metal strips welded tothe support member at distances less than about 6 meters. A ceramic usedin centralizer 566 may be, but is not limited to, Al₂O₃, MgO or otherinsulator. Centralizers 566 may be configured to maintain a location ofinsulated conductor heaters 562 on support member 564 such that movementof insulated conductor heaters may be substantially inhibited atoperating temperatures of the insulated conductor heaters. Insulatedconductor heaters 562 may also be somewhat flexible to withstandexpansion of support member 564 during heating. Centralizers 566 mayalso be configured as described in any of the embodiments herein.

[0455] Support member 564, insulated conductor heater 562, andcentralizers 566 may be placed in opening 514 in hydrocarbon containingformation 516. Insulated conductor heaters 562 may be coupled to bottomconductor junction 570 using cold pin transition conductor 568. Bottomconductor junction 570 may electrically couple each insulated conductorheater 562 to each other. Bottom conductor junction 570 may includematerials that are electrically conducting and do not melt attemperatures found in opening 514. Cold pin transition conductor 568 maybe an insulated conductor heater having lower electrical resistance thaninsulated conductor heater 562. As illustrated in FIG. 17a, cold pin 568may be coupled to transition conductor 571 and insulated conductorheater 562. Cold pin transition conductor 568 may provide a temperaturetransition between transition conductor 571 and insulated conductorheater 562.

[0456] Lead-in conductor 572 may be coupled to wellhead 590 to provideelectrical power to insulated conductor heater 562. Wellhead 590 may beconfigured as shown in FIG. 18 and as described in any of theembodiments herein. Lead-in conductor 572 may be made of a relativelylow electrical resistance conductor such that relatively little orsubstantially no heat may be generated from electrical current passingthrough lead-in conductor 572. For example, the lead-in conductor mayinclude, but may not be limited to, a rubber insulated stranded copperwire, but the lead-in conductor may also be a mineral-insulatedconductor with a copper core. Lead-in conductor 572 may couple to awellhead 590 at surface 550 through a sealing flange located betweenoverburden 540 and surface 550. The sealing flange 590 c may beconfigured as shown in FIG. 18 and as described in any of theembodiments herein. The sealing flange may substantially inhibit fluidfrom escaping from opening 514 to surface 550.

[0457] Packing material 542 (see FIG. 17) may optionally be placedbetween overburden casing 541 and opening 514. Overburden casing 541 mayinclude any materials configured to substantially contain cement 544. Inan embodiment of a heater source, overburden casing is an 7.6 cm (3inch) diameter carbon steel, schedule 40 pipe. Packing material 542 maybe configured to inhibit fluid from flowing from opening 514 to surface550. Overburden casing 541 may be placed in cement 544 in overburden 540of formation 516. Cement 544 may include, for example, Class G or ClassH Portland cement mixed with silica flour for improved high temperatureperformance, slag or silica flour, and/or a mixture thereof (e.g., about1.58 grams per cubic centimeter slag/silica flour). In selected heatsource embodiments, cement 544 extends radially a width of from about 5cm to about 25 cm. In some embodiments cement 544 may extend radially awidth of about 10 cm to about 15 cm. In some other embodiments, cement544 may be designed to inhibit heat transfer from conductor 564 intoformation 540 within the overburden.

[0458] In certain embodiments one or more conduits may be provided tosupply additional components (e.g., nitrogen, carbon dioxide, reducingagents such as gas containing hydrogen, etc.) to formation openings, tobleed off fluids, and/or to control pressure. Formation pressures tendto be highest near heating sources and thus it is often beneficial tohave pressure control equipment proximate the heating source. In someembodiments adding a reducing agent proximate the heating source assistsin providing a more favorable pyrolysis environment (e.g., a higherhydrogen partial pressure). Since permeability and porosity tend toincrease more quickly proximate the heating source, it is often optimalto add a reducing agent proximate the heating source so that thereducing agent can more easily move into the formation.

[0459] In FIG. 17, for example, conduit 5000 may be provided to add gasfrom gas source 5003, through valve 5001, and into opening 514 (anopening 5004 is provided in packing material 542 to allow gas to passinto opening 514). Conduit 5000 and valve 5002 may also be used atdifferent times to bleed off pressure and/or control pressure proximateto opening 514. In FIG. 19, for example, conduit 5010 may be provided toadd gas from gas source 5013, through valve 5011, and into opening 514(an opening is provided in cement 544 to allow gas to pass into opening514). Conduit 5010 and valve 5012 may also be used at different times tobleed off pressure and/or control pressure proximate to opening 514. Itis to be understood that any of the heating sources described herein mayalso be equipped with conduits to supply additional components, bleedoff fluids, and/or to control pressure.

[0460] Support member 564 and lead-in conductor 572 may be coupled towellhead 590 at surface 550 of formation 516. Surface conductor 545 mayenclose cement 544 and may couple to wellhead 590. Embodiments of heatersource surface conductor 545 may have a diameter of about 10.16 cm toabout 30.48 cm or, for example, a diameter of about 22 cm. Embodimentsof surface casings may extend to depths of approximately 3 m toapproximately 515 m into an opening in the formation. Alternatively, thesurface casing may extend to a depth of approximately 9 m into theopening. Electrical current may be supplied from a power source toinsulated conductor heater 562 to generate heat due to the electricalresistance of conductor 575 as illustrated in FIG. 16. As an example, avoltage of about 330 volts and a current of about 266 amps are suppliedto insulated conductors 562 to generate a heat of about 1150 watts/meterin insulated conductor heater 562. Heat generated from the threeinsulated conductor heaters 562 may transfer (e.g., by radiation) withinopening 514 to heat at least a portion of the formation 516.

[0461] An appropriate configuration of an insulated conductor heater maybe determined by optimizing a material cost of the heater based on alength of heater, a power required per meter of conductor, and a desiredoperating voltage. In addition, an operating current and voltage may bechosen to optimize the cost of input electrical energy in conjunctionwith a material cost of the insulated conductor heaters. For example, asinput electrical energy increases, the cost of materials needed towithstand the higher voltage may also increase. The insulated conductorheaters may be configured to generate a radiant heat of approximately650 watts/meter of conductor to approximately 1650 watts/meter ofconductor. The insulated conductor heater may operate at a temperaturebetween approximately 530° C. and approximately 760° C. within aformation.

[0462] Heat generated by an insulated conductor heater may heat at leasta portion of a hydrocarbon containing formation. In some embodimentsheat may be transferred to the formation substantially by radiation ofthe generated heat to the formation. Some heat may be transferred byconduction or convection of heat due to gases present in the opening.The opening may be an uncased opening. An uncased opening eliminatescost associated with thermally cementing the heater to the formation,costs associated with a casing, and/or costs of packing a heater withinan opening. In addition, the heat transfer by radiation is generallymore efficient than by conduction so the heaters will operate at lowertemperatures in an open wellbore. The conductive heat transfer may beenhanced by the addition of a gas in the opening at pressures up toabout 27 bar absolute. The gas may include, but may not be limited to,carbon dioxide and/or helium. Still another advantage is that theheating assembly will be free to undergo thermal expansion. Yet anotheradvantage is that the heaters may be replaceable.

[0463] The insulated conductor heater, as described in any of theembodiments herein, may be installed in opening 514 by any method knownin the art. In an embodiment, more than one spooling assembly may beused to install both the electric heater and a support membersimultaneously. U.S. Pat. No. 4,572,299 issued to Van Egmond et al.,which is incorporated by reference as if fully set forth herein,describes spooling an electric heater into a well. Alternatively, thesupport member may be installed using a coiled tubing unit including anyunit known in the art. The heaters may be un-spooled and connected tothe support as the support is inserted into the well. The electricheater and the support member may be un-spooled from the spoolingassemblies. Spacers may be coupled to the support member and the heateralong a length of the support member. Additional spooling assemblies maybe used for additional electric heater elements.

[0464] In an embodiment, the support member may be installed usingstandard oil field operations and welding different sections of support.Welding may be done by using orbital welding. For example, a firstsection of the support member may be disposed into the well. A secondsection (e.g., of substantially similar length) may be coupled to thefirst section in the well. The second section may be coupled by weldingthe second section to the first section. An orbital welder disposed atthe wellhead may be configured to weld the second section to the firstsection. This process may be repeated with subsequent sections coupledto previous sections until a support of desired length is within thewell.

[0465]FIG. 18 illustrates a cross-sectional view of one embodiment of awellhead coupled, e.g., to overburden casing 541. Flange 590 c may becoupled to, or may be a part of, wellhead 590. Flange 590 c may be, forexample, carbon steel, stainless steel or any other commerciallyavailable suitable sealing material. Flange 590 c may be sealed witho-ring 590 f, or any other sealing mechanism. Thermocouples 590 g may beprovided into wellhead 590 through flange 590 c. Thermocouples 590 g maymeasure a temperature on or proximate to support member 564 within theheated portion of the well. Support member 564 may be coupled to flange590 c. Support member 564 may be configured to support one or moreinsulated conductor heaters as described herein. Support member 564 maybe sealed in flange 590 c by welds 590 h. Alternately, support member564 may be sealed by any method known in the art.

[0466] Power conductor 590 a may be coupled to a lead-in cable and/or aninsulated conductor heater. Power conductor 590 a may be configured toprovide electrical energy to the insulated conductor heater. Powerconductor 590 a may be sealed in sealing flange 590 d. Sealing flange590 d may be sealed by compression seals or o-rings 590 e. Powerconductor 590 a may be coupled to support member 564 with band 590 i.Band 590 i may include a rigid and corrosion resistant material such asstainless steel. Wellhead 590 may be sealed with weld 590 h such thatfluid may be substantially inhibited from escaping the formation throughwellhead 590. Lift bolt 590 j may be configured to lift wellhead 590 andsupport member 564. Wellhead 590 may also include a pressure controlvalve. Compression fittings 590 k may serve to seal power cable 590 aand compression fittings 5901 may serve to seal thermocouple 590 g.These seals inhibit fluids from escaping the formation. The pressurecontrol valve may be configured to control a pressure within an openingin which support member 564 may be disposed.

[0467] In an embodiment, a control system may be configured to controlelectrical power supplied to an insulated conductor heater. Powersupplied to the insulated conductor heater may be controlled with anyappropriate type of controller. For alternating current, the controllermay, for example, be a tapped transformer. Alternatively, the controllermay be a zero crossover electrical heater firing SCR (silicon controlledrectifier) controller. Zero crossover electrical heater firing controlmay be achieved by allowing full supply voltage to the insulatedconductor heater to pass through the insulated conductor heater for aspecific number of cycles, starting at the “crossover,” where aninstantaneous voltage may be zero, continuing for a specific number ofcomplete cycles, and discontinuing when the instantaneous voltage againmay cross zero. A specific number of cycles may be blocked, allowingcontrol of the heat output by the insulated conductor heater. Forexample, the control system may be arranged to block fifteen and/ortwenty cycles out of each sixty cycles that may be supplied by astandard 60 Hz alternating current power supply. Zero crossover firingcontrol may be advantageously used with materials having a lowtemperature coefficient materials. Zero crossover firing control maysubstantially inhibit current spikes from occurring in an insulatedconductor heater.

[0468]FIG. 19 illustrates an embodiment of a conductor-in-conduit heaterconfigured to heat a section of a hydrocarbon containing formation.Conductor 580 may be disposed in conduit 582. Conductor 580 may be a rodor conduit of electrically conductive material. A conductor 580 may havea low resistance section 584 at both the top and the bottom of theconductor 580 in order to generate less heating in these sections 584.The substantially low resistance section 584 may be due to a greatercross-sectional area of conductor 580 in that section. For example,conductor 580 may be a 304 or 310 stainless steel rod with a diameter ofapproximately 2.8 cm. The diameter and wall thickness of conductor 580may vary, however, depending on, for example, a desired heating rate ofthe hydrocarbon containing formation. Conduit 582 may include anelectrically conductive material. For example, conduit 582 may be a 304or 310 stainless steel pipe having a diameter of approximately 7.6 cmand a thickness of approximately schedule 40. Conduit 582 may bedisposed in opening 514 in formation 516. Opening 514 may have adiameter of at least approximately 5 cm. The diameter of the opening mayvary, however, depending on, for example, a desired heating rate in theformation and/or a diameter of conduit 582. For example, a diameter ofthe opening may be from about 10 cm to about 13 cm. Larger diameteropenings may also be used. For example, a larger opening may be used ifmore than one conductor is to be placed within a conduit.

[0469] Conductor 580 may be centered in conduit 582 through centralizer581. Centralizer 581 may electrically isolate conductor 580 from conduit582. In addition, centralizer 581 may be configured to locate conductor580 within conduit 582. Centralizer 581 may be made of a ceramicmaterial or a combination of ceramic and metallic materials. More thanone centralizer 581 may be configured to substantially inhibitdeformation of conductor 580 in conduit 582 during use. More than onecentralizer 581 may be spaced at intervals between approximately 0.5 mand approximately 3 m along conductor 580. Centralizer 581 may be madeof ceramic, 304 stainless steel, 310 stainless steel, or other types ofmetal. Centralizer 581 may be configured as shown in FIG. 22 and/orFIGS. 23a and 23 b.

[0470] As depicted in FIG. 20, sliding connector 583 may couple an endof conductor 580 disposed proximate a lowermost surface of conduit 582.Sliding connector 583 allows for differential thermal expansion betweenconductor 580 and conduit 582. Sliding connector 583 is attached to aconductor 580 located at the bottom of the well at a low resistancesection 584 which may have a greater cross-sectional area. The lowerresistance of section 584 allows the sliding connector to operate attemperatures no greater than about 90° C. In this manner, corrosion ofthe sliding connector components is minimized and therefore contactresistance between sliding connector 583 and conduit 582 is alsominimized. Sliding connector 583 may be configured as shown in FIG. 20and as described in any of the embodiments herein. The substantially lowresistance section 584 of the conductor 580 may couple conductor 580 towellhead 690 as depicted in FIG. 19. Wellhead 690 may be configured asshown in FIG. 21 and as described in any of the embodiments herein.Electrical current may be applied to conductor 580 from power cable 585through a low resistance section 584 of the conductor 580. Electricalcurrent may pass from conductor 580 through sliding connector 583 toconduit 582. Conduit 582 may be electrically insulated from overburdencasing 541 and from wellhead 690 to return electrical current to powercable 585. Heat may be generated in conductor 580 and conduit 582. Thegenerated heat may radiate within conduit 582 and opening 514 to heat atleast a portion of formation 516. As an example, a voltage of about 330volts and a current of about 795 amps may be supplied to conductor 580and conduit 582 in a 229 m (750 ft) heated section to generate about1150 watts/meter of conductor 580 and conduit 582.

[0471] Overburden conduit 541 may be disposed in overburden 540 offormation 516. Overburden conduit 541 may in some embodiments besurrounded by materials that may substantially inhibit heating ofoverburden 540. A substantially low resistance section 584 of aconductor 580 may be placed in overburden conduit 541. The substantiallylow resistance section 584 of conductor 580 may be made of, for example,carbon steel. The substantially low resistance section 584 may have adiameter between about 2 cm to about 5 cm or, for example, a diameter ofabout 4 cm. A substantially low resistance section 584 of conductor 580may be centralized within overburden conduit 541 using centralizers 581.Centralizers 581 may be spaced at intervals of approximately 6 m toapproximately 12 m or, for example, approximately 9 m alongsubstantially low resistance section 584 of conductor 580. Asubstantially low resistance section 584 of conductor 580 may be coupledto conductor 580 using any method known in the art such as arc welding.A substantially low resistance section 584 may be configured to generatelittle and/or substantially no heat in overburden conduit 541. Packingmaterial 542 may be placed between overburden casing 541 and opening514. Packing material 542 may be configured to substantially inhibitfluid from flowing from opening 514 to surface 550 or to inhibit mostheat carrying fluids from flowing from opening 514 to surface 550.

[0472] Overburden conduit may include, for example, a conduit of carbonsteel having a diameter of about 7.6 cm and a thickness of aboutschedule 40 pipe. Cement 544 may include, for example, slag or silicaflour, or a mixture thereof (e.g., about 1.58 grams per cubic centimeterslag/silica flour). Cement 544 may extend radially a width of about 5 cmto about 25 cm. Cement 544 may also be made of material designed toinhibit flow of heat into formation 516.

[0473] Surface conductor 545 and overburden casing 541 may enclosecement 544 and may couple to wellhead 690. Surface conductor 545 mayhave a diameter of about 10 cm to about 30 cm and more preferably adiameter of about 22 cm. Electrically insulating sealing flanges may beconfigured to mechanically couple substantially low resistance section584 of conductor 580 to wellhead 690 and to electrically couple lowerresistance section 584 to power cable 585. The electrically insulatingsealing flanges may be configured to couple lead-in conductor 585 towellhead 690. For example, lead-in conductor 585 may include a coppercable, wire, or other elongated member. Lead-in conductor 585 mayinclude, however, any material having a substantially low resistance.The lead-in conductor may be clamped to the bottom of the lowresistivity conductor to make electrical contact.

[0474] In an embodiment, heat may be generated in or by conduit 582. Inthis manner, about 10% to about 30%, or, for example, about 20%, of thetotal heat generated by the heater may be generated in or by conduit582. Both conductor 580 and conduit 582 may be made of stainless steel.Dimensions of conductor 580 and conduit 582 may be chosen such that theconductor will dissipate heat in a range from approximately 650 wattsper meter to 1650 watts per meter. A temperature in conduit 582 may beapproximately 480° C. to approximately 815° C. and a temperature inconductor 580 may be approximately 500° C. to 840° C. Substantiallyuniform heating of a hydrocarbon containing formation may be providedalong a length of conduit 582 greater than about 300 m or, maybe,greater than about 600 m. A length of conduit 582 may vary, however,depending on, for example, a type of hydrocarbon containing formation, adepth of an opening in the formation, and/or a length of the formationdesired for treating.

[0475] The generated heat may be configured to heat at least a portionof a hydrocarbon containing formation. Heating of at least the portionmay occur substantially by radiation of the generated heat within anopening in the formation and to a lesser extent by gas conduction. Inthis manner, a cost associated with filling the opening with a fillingmaterial to provide conductive heat transfer between the insulatedconductor and the formation may be eliminated. In addition, heattransfer by radiation is generally more efficient than by conduction sothe heaters will generally operate at lower temperatures in an openwellbore. Still another advantage is that the heating assembly will befree to undergo thermal expansion. Yet another advantage is that theheater may be replaceable.

[0476] The conductor-in-conduit heater, as described in any of theembodiments herein, may be installed in opening 514. In an embodiment,the conductor-in-conduit heater may be installed into a well bysections. For example, a first section of the conductor-in-conduitheater may be disposed into the well. The section may be about 12 m inlength. A second section (e.g., of substantially similar length) may becoupled to the first section in the well. The second section may becoupled by welding the second section to the first section and/or withthreads disposed on the first and second section. An orbital welderdisposed at the wellhead may be configured to weld the second section tothe first section. This process may be repeated with subsequent sectionscoupled to previous sections until a heater of desired length may bedisposed in the well. In some embodiments, three sections may be coupledprior to being disposed in the well. The three sections may be coupledby welding. The three sections may have a length of about 12.2 m each.The resulting 37 m section may be lifted vertically by a crane at thewellhead. The three sections may be coupled to three additional sectionsin the well as described herein. Welding the three sections prior tobeing disposed in the well may reduce a number of leaks and/or faultywelds and may decrease a time required for installation of the heater.

[0477] In an alternate embodiment, the conductor-in-conduit heater maybe spooled onto a spooling assembly. The spooling assembly may bemounted on a transportable structure. The transportable structure may betransported to a well location. The conductor-in-conduit heater may beun-spooled from the spooling assembly into the well.

[0478]FIG. 20 illustrates an embodiment of a sliding connector. Slidingconnector 583 may include scraper 593 that may abut an inner surface ofconduit 582 at point 595. Scraper 593 may include any metal orelectrically conducting material (e.g., steel or stainless steel).Centralizer 591 may couple to conductor 580. In some embodiments,conductor 580 may have a substantially low resistance section 584, dueto an increased thickness, substantially around a location of slidingconnector 583. Centralizer 591 may include any electrically conductingmaterial (e.g., a metal or metal alloy). Centralizer 591 may be coupledto scraper 593 through spring bow 592. Spring bow 592 may include anymetal or electrically conducting material (e.g., copper-berylliumalloy). Centralizer 591, spring bow 592, and/or scraper 593 may becoupled through any welding method known in the art. Sliding connector583 may electrically couple the substantially low resistance section 584of conductor 580 to conduit 582 through centralizer 591, spring bow 592,and/or scraper 593. During heating of conductor 580, conductor 580 mayexpand at a substantially different rate than conduit 582. For example,point 594 on conductor 580 may move relative to point 595 on conduit 582during heating of conductor 580. Scraper 593 may maintain electricalcontact with conduit 582 by sliding along surface of conduit 582.Several sliding connectors may be used for redundancy and to reduce thecurrent at each scraper. In addition, a thickness of conduit 582 may beincreased for a length substantially adjacent to sliding connector 583to substantially reduce heat generated in that portion of the conduit582. The length of conduit 582 with increased thickness may be, forexample, approximately 6 m.

[0479]FIG. 21 illustrates another embodiment of a wellhead. Wellhead 690may be coupled to electrical junction box 690 a by flange 690 n or anyother suitable mechanical device. Electrical junction box 690 a may beconfigured to control power (current and voltage) supplied to anelectric heater. The electric heater may be a conductor-in-conduitheater as described herein. Flange 690 n may include, for example,stainless steel or any other suitable sealing material. Conductor 690 bmay be disposed in flange 690 n and may electrically couple overburdencasing 541 to electrical junction box 690 a. Conductor 690 b may includeany metal or electrically conductive material (e.g., copper).Compression seal 690 c may seal conductor 690 b at an inner surface ofelectrical junction box 690 a.

[0480] Flange 690 n may be sealed with metal o-ring 690 d. Conduit 690f, which may be, e.g., a pipe, may couple flange 690 n to flange 690 m.Flange 690 m may couple to overburden casing 541. Flange 690 m may besealed with o-ring 690 g (e.g., metal o-ring or steel o-ring). Thesubstantially low resistance section 584 of the conductor (e.g.,conductor 580) may couple to electrical junction box 690 a. Thesubstantially low resistance section 584 may be passed through flange690 n and may be sealed in flange 690 n with o-ring assembly 690 p.Assemblies 690 p are designed to insulate the substantially lowresistance section 584 of conductor 580 from flange 690 n and flange 690m. O-ring assembly 690 c may be designed to electrically insulateconductor 690 b from flange 690 m and junction box 690 a. Centralizer581 may couple to low resistance section 584. Electrically insulatingcentralizer 581 may have characteristics as described in any of theembodiments herein. Thermocouples 690 i may be coupled to thermocoupleflange 690 q with connectors 690 h and wire 690 j. Thermocouples 690 imay be enclosed in an electrically insulated sheath (e.g., a metalsheath). Thermocouples 690 i may be sealed in thermocouple flange 690 qwith compression seals 690 k. Thermocouples 690 i may be used to monitortemperatures in the heated portion downhole.

[0481]FIG. 22 illustrates a perspective view of an embodiment of acentralizer in, e.g., conduit 582. Electrical insulator 581 a may bedisposed on conductor 580. Insulator 581 a may be made of, for example,aluminum oxide or any other electrically insulating material that may beconfigured for use at high temperatures. A location of insulator 581 aon the conductor 580 may be maintained by disc 581 d. Disc 581 d may bewelded to conductor 580. Spring bow 581 c may be coupled to insulator581 a by disc 581 b. Spring bow 581 c and disc 581 b may be made ofmetals such as 310 stainless steel and any other thermally conductingmaterial that may be configured for use at high temperatures.Centralizer 581 may be arranged as a single cylindrical member disposedon conductor 580. Centralizer 581 may be arranged as twohalf-cylindrical members disposed on conductor 580. The twohalf-cylindrical members may be coupled to conductor 580 by band 581 e.Band 581 e may be made of any material configured for use at hightemperatures (e.g., steel).

[0482]FIG. 23a illustrates a cross-sectional view of an embodiment of acentralizer 581 e disposed on conductor 580. FIG. 23b illustrates aperspective view of the embodiment shown in FIG. 23a. Centralizer 581 emay be made of any suitable electrically insulating material that maysubstantially withstand high voltage at high temperatures. Examples ofsuch materials may be aluminum oxide and/or Macor. Discs 581 d maymaintain positions of centralizer 581 e relative to conductor 580. Discs581 d may be metal discs welded to conductor 580. Discs 581 d may betack-welded to conductor 580. Centralizer 581 e may substantiallyelectrically insulate conductor 580 from conduit 582.

[0483] In an embodiment, a conduit may be pressurized with a fluid tobalance a pressure in the conduit with a pressure in an opening. In thismanner, deformation of the conduit may be substantially inhibited. Athermally conductive fluid may be configured to pressurize the conduit.The thermally conductive fluid may increase heat transfer within theconduit. The thermally conductive fluid may include a gas such ashelium, nitrogen, air, or mixtures Thereof. A pressurized fluid may alsobe configured to pressurize the conduit such that the pressurized fluidmay inhibit arcing between the conductor and the conduit. If air and/orair mixtures are used to pressurize the conduit, the air and/or airmixtures may react with materials of the conductor and the conduit toform an oxide on a surface of the conductor and the conduit such thatthe conductor and the conduit are at least somewhat more resistant tocorrosion.

[0484] An emissivity of a conductor and/or a conduit may be increased.For example, a surface of the conductor and/or the conduit may beroughened to increase the emissivity. Blackening the surface of theconductor and/or the conduit may also increase the emissivity.Alternatively, oxidation of the conductor and/or the conduit prior toinstallation may be configured to increase the emissivity. The conductorand/or the conduit may also be oxidized by heating the conductor and/orthe conduit in the presence of an oxidizing fluid in the conduit and/orin an opening in a hydrocarbon containing formation. Another alternativefor increasing the emissivity may be to anodize the conductor and/or theconduit such that the surface may be roughened and/or blackened.

[0485] In another embodiment, a perforated tube may be placed in theopening formed in the hydrocarbon containing formation proximate to andexternal the first conduit. The perforated tube may be configured toremove fluids formed in the opening. In this manner, a pressure may bemaintained in the opening such that deformation of the first conduit maybe substantially inhibited and the pressure in the formation near theheaters may be reduced. The perforated tube may also be used to increaseor decrease pressure in the formation by addition or removal of a fluidor fluids from the formation. This may allow control of the pressure inthe formation and control of quality of produced hydrocarbons.Perforated tubes may be used for pressure control in all describedembodiments of heat sources using an open hole configuration. Theperforated tube may also be configured to inject gases to upgradehydrocarbon properties in situ; for example, hydrogen gas may beinjected under elevated pressure.

[0486]FIG. 24 illustrates an alternative embodiment of aconductor-in-conduit heater configured to heat a section of ahydrocarbon containing formation. Second conductor 586 may be disposedin conduit 582 in addition to conductor 580. Conductor 580 may beconfigured as described herein. Second conductor 586 may be coupled toconductor 580 using connector 587 located near a lowermost surface ofconduit 582. Second conductor 586 may be configured as a return path forthe electrical current supplied to conductor 580. For example, secondconductor 586 may return electrical current to wellhead 690 throughsecond substantially low resistance conductor 588 in overburden casing541. Second conductor 586 and conductor 580 may be configured of anelongated conductive material. Second conductor 586 and conductor 580may be, for example, a stainless steel rod having a diameter ofapproximately 2.4 cm. Connector 587 may be flexible. Conduit 582 may beelectrically isolated from conductor 580 and second conductor 586 usingcentralizers 581. Overburden casing 541, cement 544, surface conductor545, and packing material 542 may be configured as described in theembodiment shown in FIG. 19. Advantages of this embodiment include theabsence of a sliding contactor, which may extend the life of the heater,and the isolation of all applied power from formation 516.

[0487] In another embodiment, a second conductor may be disposed in asecond conduit, and a third conductor may be disposed in a thirdconduit. The second opening may be different from the opening for thefirst conduit. The third opening may be different from the opening forthe first conduit and the second opening. For example, each of thefirst, second, and third openings may be disposed in substantiallydifferent well locations of the formation and may have substantiallysimilar dimensions. The first, second, and third conductors may beconfigured as described herein. The first, second, and third conductorsmay be electrically coupled in a 3-phase Y electrical configuration. Theouter conduits may be connected together or may be connected to theground. The 3-phase Y electrical configuration may provide a safer, moreefficient method to heat a hydrocarbon containing formation than using asingle conductor. The first, second, and/or third conduits may beelectrically isolated from the first, second, and third conductors,respectively. Dimensions of each conductor and each conduit may beconfigured such that each conductor may generate heat of approximately650 watts per meter of conductor to approximately 1650 watts per meterof conductor. In an embodiment, a first conductor and a second conductorin a conduit may be coupled by a flexible connecting cable. The bottomof the first and second conductor may be enlarged to create lowresistance sections, and thus generate less heat. In this manner, theflexible connector may be made of, for example, stranded copper coveredwith rubber insulation.

[0488] In an embodiment, a first conductor and a second conductor may becoupled to at least one sliding connector within a conduit. The slidingconnector may be configured as described herein. For example, such asliding connector may be configured to generate less heat than the firstconductor or the second conductor. The conduit may be electricallyisolated from the first conductor, second conductor, and/or the slidingconnector. The sliding connector may be placed in a location within thefirst conduit where substantially less heating of the hydrocarboncontaining formation may be required.

[0489] In an embodiment, a thickness of a section of a conduit may beincreased such that substantially less heat may be transferred (e.g.,radiated) along the section of increased thickness. The section withincreased thickness may preferably be formed along a length of theconduit where less heating of the hydrocarbon containing formation maybe required.

[0490] In an embodiment, the conductor may be formed of sections ofvarious metals that are welded together. The cross sectional area of thevarious metals may be selected to allow the resulting conductor to belong, to be creep resistant at high operating temperatures, and/or todissipate substantially the same amount of heat per unit length alongthe entire length of the conductor. For example, a first section may bemade of a creep resistant metal (such as, but not limited to, Inconel617 or HR120) and a second section of the conductor may be made of 304stainless steel. The creep resistant first section may help to supportthe second section. The cross sectional area of the first section may belarger than the cross sectional area of the second section. The largercross sectional area of the first section may allow for greater strengthof the first section. Higher resistivity properties of the first sectionmay allow the first section to dissipate the same amount of heat perunit length as the smaller cross sectional area second section.

[0491] In some embodiments, the cross sectional area and/or the metalused for a particular section may be chosen so that a particular sectionprovides greater (or lesser) heat dissipation per unit length than anadjacent section. More heat may be provided near an interface between ahydrocarbon layer and a non-hydrocarbon layer (e.g., the overburden andthe hydrocarbon containing formation) to counteract end effects andallow for more uniform heat dissipation into the hydrocarbon containingformation. A higher heat dissipation may also be located at a lower endof an elongated member to counteract end effects and allow for moreuniform heat dissipation.

[0492] In an embodiment, an elongated member may be disposed within anopening (e.g., an open wellbore) in a hydrocarbon containing formation.The opening may preferably be an uncased opening in the hydrocarboncontaining formation. The opening may have a diameter of at leastapproximately 5 cm or, for example, approximately 8 cm. The diameter ofthe opening may vary, however, depending on, for example, a desiredheating rate in the formation. The elongated member may be a length(e.g., a strip) of metal or any other elongated piece of metal (e.g., arod). The elongated member may include stainless steel. The elongatedmember, however, may also include any conductive material configurableto generate heat to sufficiently heat a portion of the formation and tosubstantially withstand a corresponding temperature within the opening,for example, it may be configured to withstand corrosion at thetemperature within the opening.

[0493] An elongated member may be a bare metal heater. “Bare metal”refers to a metal that does not include a layer of electricalinsulation, such as mineral insulation, that is designed to provideelectrical insulation for the metal throughout an operating temperaturerange of the elongated member. Bare metal may encompass a metal thatincludes a corrosion inhibiter such as a naturally occurring oxidationlayer, an applied oxidation layer, and/or a film. Bare metal includesmetal with polymeric or other types of electrical insulation that cannotretain electrical insulating properties at typical operating temperatureof the elongated member. Such material may be placed on the metal andmay be thermally degraded during use of the heater.

[0494] An elongated member may have a length of about 650 meters. Longerlengths may be achieved using sections of high strength alloys, but suchelongated members may be expensive. In some embodiments, an elongatedmember may be supported by a plate in a wellhead. The elongated membermay include sections of different conductive materials that are weldedtogether end-to-end. A large amount of electrically conductive weldmaterial may be used to couple the separate sections together toincrease strength of the resulting member and to provide a path forelectricity to flow that will not result in arcing and/or corrosion atthe welded connections. The different conductive materials may includealloys with a high creep resistance. The sections of differentconductive materials may have varying diameters to ensure uniformheating along the elongated member. A first metal that has a highercreep resistance than a second metal typically has a higher resistivitythan the second metal. The difference in resistivities may allow asection of larger cross sectional area, more creep resistant first metalto dissipate the same amount of heat as a section of smaller crosssectional area second metal. The cross sectional areas of the twodifferent metals may be tailored to result in substantially the sameamount of heat dissipation in two welded together sections of themetals. The conductive materials may include, but are not limited to,617 Inconel, HR-120, 316 stainless steel, and 304 stainless steel. Forexample, an elongated member may have a 60 meter section of 617 Inconel,60 meter section of HR-120, and 150 meter section of 304 stainlesssteel. In addition, the elongated member may have a low resistancesection that may run from the wellhead through the overburden. This lowresistance section may decrease the heating within the formation fromthe wellhead through the overburden. The low resistance section may bethe result of, for example, choosing a substantially electricallyconductive material and/or increasing the cross-sectional area availablefor electrical conduction.

[0495] Alternately, a support member may extend through the overburden,and the bare metal elongated member or members may be coupled to aplate, a centralizer or other type of support member near an interfacebetween the overburden and the hydrocarbon formation. A low resistivitycable, such as a stranded copper cable, may extend along the supportmember and may be coupled to the elongated member or members. The coppercable may be coupled to a power source that supplies electricity to theelongated member or members.

[0496]FIG. 25 illustrates an embodiment of a plurality of elongatedmembers configured to heat a section of a hydrocarbon containingformation. Two or more (e.g., four) elongated members 600 may besupported by support member 604. Elongated members 600 may be coupled tosupport member 604 using insulated centralizers 602. Support member 604may be a tube or conduit. Support member 604 may also be a perforatedtube. Support member 604 may be configured to provide a flow of anoxidizing fluid into opening 514. Support member 604 may have a diameterbetween about 1.2 cm to about 4 cm and more preferably about 2.5 cm.Support member 604, elongated members 600, and insulated centralizers602 may be disposed in opening 514 in formation 516. Insulatedcentralizers 602 may be configured to maintain a location of elongatedmembers 600 on support member 604 such that lateral movement ofelongated members 600 may be substantially inhibited at temperatureshigh enough to deform support member 604 or elongated members 600.Insulated centralizers 602 may be a centralizer as described herein.Elongated members 600, in some embodiments, may be metal strips of about2.5 cm wide and about 0.3 cm thick stainless steel. Elongated members600, however, may also include a pipe or a rod formed of a conductivematerial. Electrical current may be applied to elongated members 600such that elongated members 600 may generate heat due to electricalresistance.

[0497] Elongated members 600 may be configured to generate heat ofapproximately 650 watts per meter of elongated members 600 toapproximately 1650 watts per meter of elongated members 600. In thismanner, elongated members 600 may be at a temperature of approximately480° C. to approximately 815° C. Substantially uniform heating of ahydrocarbon containing formation may be provided along a length ofelongated members 600 greater than about 305 m or, maybe, greater thanabout 610 m. A length of elongated members 600 may vary, however,depending on, for example, a type of hydrocarbon containing formation, adepth of an opening in the formation, and/or a length of the formationdesired for treating Elongated members 600 may be electrically coupledin series. Electrical current may be supplied to elongated members 600using lead-in conductor 572. Lead-in conductor 572 may be furtherconfigured as described herein. Lead-in conductor 572 may be coupled towellhead 690. Electrical current may be returned to wellhead 690 usinglead-out conductor 606 coupled to elongated members 600. Lead-inconductor 572 and lead-out conductor 606 may be coupled to wellhead 690at surface 550 through a sealing flange located between wellhead 690 andoverburden 540. The sealing flange may substantially inhibit fluid fromescaping from opening 514 to surface 550. Lead-in conductor 572 andlead-out conductor 606 may be coupled to elongated members using a coldpin transition conductor. The cold pin transition conductor may includean insulated conductor of substantially low resistance such thatsubstantially no heat may be generated by the cold pin transitionconductor. The cold pin transition conductor may be coupled to lead-inconductor 572, lead-out conductor 606, and/or elongated members 600 byany splicing or welding methods known in the art. The cold pintransition conductor may provide a temperature transition betweenlead-in conductor 572, lead-out conductor 606, and/or elongated members600. The cold pin transition conductor may be further configured asdescribed in any of the embodiments herein. Lead-in conductor 572 andlead-out conductor 606 may be made of low resistance conductors suchthat substantially no heat may be generated from electrical currentpassing through lead-in conductor 572 and lead-out conductor 606.

[0498] Weld beads may be placed beneath the centralizers 602 on thesupport member 604 to fix the position of the centralizers. Weld beadsmay be placed on the elongated members 600 above the uppermostcentralizer to fix the position of the elongated members relative to thesupport member (other types of connecting mechanisms may also be used).When heated, the elongated member may thermally expand downwards. Theelongated member may be formed of different metals at differentlocations along a length of the elongated member to allow relativelylong lengths to be formed. For example, a “U” shaped elongated membermay include a first length formed of 310 stainless steel, a secondlength formed of 304 stainless steel welded to the first length, and athird length formed of 310 stainless steel welded to the second length.310 stainless steel is more resistive than 304 stainless steel and maydissipate approximately 25% more energy per unit length than 304stainless steel of the same dimensions. 310 stainless steel may be morecreep resistant than 304 stainless steel. The first length and the thirdlength may be formed with cross sectional areas that allow the firstlength and third lengths to dissipate as much heat as a smaller crossarea section of 304 stainless steel. The first and third lengths may bepositioned close to the wellhead 690. The use of different types ofmetal may allow the formation of long elongated members. The differentmetals may be, but are not limited to, 617 Inconel, HR120, 316 stainlesssteel, 310 stainless steel, and 304 stainless steel.

[0499] Packing material 542 may be placed between overburden casing 541and opening 514. Packing material 542 may be configured to inhibit fluidflowing from opening 514 to surface 550 and to inhibit correspondingheat losses towards the surface. Packing material 542 may be furtherconfigured as described herein. Overburden casing 541 may be placed incement 544 in overburden 540 of formation 516. Overburden casing 541 maybe further configured as described herein. Surface conductor 545 may bedisposed in cement 544. Surface conductor 545 may be configured asdescribed herein. Support member 604 may be coupled to wellhead 690 atsurface 550 of formation 516. Centralizer 581 may be configured tomaintain a location of support member 604 within overburden casing 541.Centralizer 581 may be further configured as described herein.Electrical current may be supplied to elongated members 600 to generateheat. Heat generated from elongated members 600 may radiate withinopening 514 to heat at least a portion of formation 516.

[0500] The oxidizing fluid may be provided along a length of theelongated members 600 from oxidizing fluid source 508. The oxidizingfluid may inhibit carbon deposition on or proximate to the elongatedmembers. For example, the oxidizing fluid may react with hydrocarbons toform carbon dioxide, which may be removed from the opening. Openings 605in support member 604 may be configured to provide a flow of theoxidizing fluid along the length of elongated members 600. Openings 605may be critical flow orifices as configured and described herein.Alternatively, a tube may be disposed proximate to elongated members 600to control the pressure in the formation as described in aboveembodiments. In another embodiment, a tube may be disposed proximate toelongated members 600 to provide a flow of oxidizing fluid into opening514. Also, at least one of elongated members 600 may include a tubehaving openings configured to provide the flow of oxidizing fluid.Without the flow of oxidizing fluid, carbon deposition may occur on orproximate to elongated members 600 or on insulated centralizers 602,thereby causing shorting between elongated members 600 and insulatedcentralizers 602 or hot spots along elongated members 600. The oxidizingfluid may be used to react with the carbon in the formation as describedherein. The heat generated by reaction with the carbon may complement orsupplement the heat generated electrically.

[0501] In an embodiment, a plurality of elongated members may besupported on a support member disposed in an opening. The plurality ofelongated members may be electrically coupled in either a series orparallel configuration. A current and voltage applied to the pluralityof elongated members may be selected such that the cost of theelectrical supply of power at the surface in conjunction with the costof the plurality of elongated members may be minimized. In addition, anoperating current and voltage may be chosen to optimize a cost of inputelectrical energy in conjunction with a material cost of the elongatedmembers. The elongated members may be configured to generate and radiateheat as described herein. The elongated members may be installed inopening 514 as described herein.

[0502] In an embodiment, a bare metal elongated member may be formed ina “U” shape (or hairpin) and the member may be suspended from a wellheador from a positioner placed at or near an interface between theoverburden and the formation to be heated. In certain embodiments, thebare metal heaters are formed of rod stock. Cylindrical, high aluminaceramic electrical insulators may be placed over legs of the elongatedmembers. Tack welds along lengths of the legs may fix the position ofthe insulators. The insulators may inhibit the elongated member fromcontacting the formation or a well casing (if the elongated member isplaced within a well casing). The insulators may also inhibit legs ofthe “U” shaped members from contacting each other. High alumina ceramicelectrical insulators may be purchased from Cooper Industries (Houston,Texas). In an embodiment, the “U” shaped member may be formed ofdifferent metals having different cross sectional areas so that theelongated members may be relatively long and may dissipate substantiallythe same amount of heat per unit length along the entire length of theelongated member. The use of different welded together sections mayresult in an elongated member that has large diameter sections near atop of the elongated member and a smaller diameter section or sectionslower down a length of the elongated member. For example, an embodimentof an elongated member has two ⅞ inch (2.2 cm) diameter first sections,two ½ inch (1.3 cm) middle sections, and a ⅜ inch (0.95 cm) diameterbottom section that is bent into a “U” shape. The elongated member maybe made of materials with other cross section shapes such as ovals,squares, rectangles, triangles, etc. The sections may be formed ofalloys that will result in substantially the same heat dissipation perunit length for each section.

[0503] In some embodiments, the cross sectional area and/or the metalused for a particular section may be chosen so that a particular sectionprovides greater (or lesser) heat dissipation per unit length than anadjacent section. More heat dissipation per unit length may be providednear an interface between a hydrocarbon layer and a non-hydrocarbonlayer (e.g., the overburden and the hydrocarbon containing formation) tocounteract end effects and allow for more uniform heat dissipation intothe hydrocarbon containing formation. A higher heat dissipation may alsobe located at a lower end of an elongated member to counteract endeffects and allow for more uniform heat dissipation.

[0504]FIG. 26 illustrates an embodiment of a surface combustorconfigured to heat a section of a hydrocarbon containing formation. Fuelfluid 611 may be provided into burner 610 through conduit 617. Anoxidizing fluid may be provided into burner 610 from oxidizing fluidsource 508. Fuel fluid 611 may be oxidized with the oxidizing fluid inburner 610 to form oxidation products 613. Fuel fluid 611 may include,for example, hydrogen. Fuel fluid 611 may also include methane or anyother hydrocarbon fluids. Burner 610 may be located external toformation 516 or within an opening 614 in the hydrocarbon containingformation 516. Flame 618 may be configured to heat fuel fluid 611 to atemperature sufficient to support oxidation in burner 610. Flame 618 maybe configured to heat fuel fluid 611 to a temperature of about 1425° C.Flame 618 may be coupled to an end of conduit 617. Flame 618 may be apilot flame. The pilot flame may be configured to burn with a small flowof fuel fluid 611. Flame 618 may, however, be an electrical ignitionsource.

[0505] Oxidation products 613 may be provided into opening 614 withininner conduit 612 coupled to burner 610. Heat may be transferred fromoxidation products 613 through outer conduit 615 into opening 614 and toformation 516 along a length of inner conduit 612. Therefore, oxidationproducts 613 may substantially cool along the length of inner conduit612. For example, oxidation products 613 may have a temperature of about870° C. proximate top of inner conduit 612 and a temperature of about650° C. proximate bottom of inner conduit 612. A section of innerconduit 612 proximate to burner 610 may have ceramic insulator 612 bdisposed on an inner surface of inner conduit 612. Ceramic insulator 612b may be configured to substantially inhibit melting of inner conduit612 and/or insulation 612 a proximate to burner 610. Opening 614 mayextend into the formation a length up to about 550 m below surface 550.

[0506] Inner conduit 612 may be configured to provide oxidation products613 into outer conduit 615 proximate a bottom of opening 614. Innerconduit 612 may have insulation 612 a. FIG. 27 illustrates an embodimentof inner conduit 612 with insulation 612 a and ceramic insulator 612 bdisposed on an inner surface of inner conduit 612. Insulation 612 a maybe configured to substantially inhibit heat transfer between fluids ininner conduit 612 and fluids in outer conduit 615. A thickness ofinsulation 612 a may be varied along a length of inner conduit 612 suchthat heat transfer to formation 516 may vary along the length of innerconduit 612. For example, a thickness of insulation 612 a may be taperedto from a larger thickness to a lesser thickness from a top portion to abottom portion, respectively, of inner conduit 612 in opening 614. Sucha tapered thickness may provide substantially more uniform heating offormation 516 along the length of inner conduit 612 in opening 614.Insulation 612 a may include ceramic and metal materials. Oxidationproducts 613 may return to surface 550 through outer conduit 615. Outerconduit may have insulation 615 a as depicted in FIG. 26. Insulation 615a may be configured to substantially inhibit heat transfer from outerconduit 615 to overburden 540.

[0507] Oxidation products 613 may be provided to an additional burnerthrough conduit 619 at surface 550. Oxidation products 613 may beconfigured as a portion of a fuel fluid in the additional burner. Doingso may increase an efficiency of energy output versus energy input forheating formation 516. The additional burner may be configured toprovide heat through an additional opening in formation 516.

[0508] In some embodiments, an electric heater may be configured toprovide heat in addition to heat provided from a surface combustor. Theelectric heater may be, for example, an insulated conductor heater or aconductor-in-conduit heater as described in any of the aboveembodiments. The electric heater may be configured to provide theadditional heat to a hydrocarbon containing formation such that thehydrocarbon containing formation may be heated substantially uniformlyalong a depth of an opening in the formation.

[0509] Flameless combustors such as those described in U.S. Pat. No.5,255,742 to Mikus et al., U.S. Pat. No. 5,404,952 to Vinegar et al.,U.S. Pat. No. 5,862,858 to Wellington et al., and U.S. Pat. No.5,899,269 to Wellington et al., which are incorporated by reference asif fully set forth herein, may be configured to heat a hydrocarboncontaining formation.

[0510]FIG. 28 illustrates an embodiment of a flameless combustorconfigured to heat a section of the hydrocarbon containing formation.The flameless combustor may include center tube 637 disposed withininner conduit 638. Center tube 637 and inner conduit 638 may be placedwithin outer conduit 636. Outer conduit 636 may be disposed withinopening 514 in formation 516. Fuel fluid 621 may be provided into theflameless combustor through center tube 637. Fuel fluid 621 may includeany of the fuel fluids described herein. If a hydrocarbon fuel such asmethane is utilized, it may be mixed with steam to prevent coking incenter tube 637. If hydrogen is used as the fuel, no steam may berequired.

[0511] Center tube 637 may include flow mechanisms 635 (e.g., floworifices) disposed within an oxidation region to allow a flow of fuelfluid 621 into inner conduit 638. Flow mechanisms 635 may control a flowof fuel fluid 621 into inner conduit 638 such that the flow of fuelfluid 621 is not dependent on a pressure in inner conduit 638. Flowmechanisms 635 may have characteristics as described herein. Oxidizingfluid 623 may be provided into the combustor through inner conduit 638.Oxidizing fluid 623 may be provided from oxidizing fluid source 508.Oxidizing fluid 623 may include any of the oxidizing fluids as describedin above embodiments. Flow mechanisms 635 on center tube 637 may beconfigured to inhibit flow of oxidizing fluid 623 into center tube 637.

[0512] Oxidizing fluid 621 may mix with fuel fluid 621 in the oxidationregion of inner conduit 638. Either oxidizing fluid 623 or fuel fluid621, or a combination of both, may be preheated external to thecombustor to a temperature sufficient to support oxidation of fuel fluid621. Oxidation of fuel fluid 621 may provide heat generation withinouter conduit 636. The generated heat may provide heat to at least aportion of a hydrocarbon containing formation proximate to the oxidationregion of inner conduit 638. Products 625 from oxidation of fuel fluid621 may be removed through outer conduit 636 outside inner conduit 638.Heat exchange between the downgoing oxidizing fluid and the upgoingcombustion products in the overburden results in enhanced thermalefficiency. A flow of removed combustion products 625 may be balancedwith a flow of fuel fluid 621 and oxidizing fluid 623 to maintain atemperature above autoignition temperature but below a temperaturesufficient to produce substantial oxides of nitrogen. Also, a constantflow of fluids may provide a substantially uniform temperaturedistribution within the oxidation region of inner conduit 638. Outerconduit 636 may be, for example, a stainless steel tube. In this manner,heating of at least the portion of the hydrocarbon containing formationmay be substantially uniform. As described above, the lower operatingtemperature may also provide a less expensive metallurgical costassociated with the heating system.

[0513] Certain heat source embodiments may include an operating systemthat is coupled to any of heat sources such by insulated conductors orother types of wiring. The operating system may be configured tointerface with the heat source. The operating system may receive asignal (e.g., an electromagnetic signal) from a heater that isrepresentative of a temperature distribution of the heat source.Additionally, the operating system may be further configured to controlthe heat source, either locally or remotely. For example, the operatingsystem may alter a temperature of the heat source by altering aparameter of equipment coupled to the heat source. Therefore, theoperating system may monitor, alter, and/or control the heating of atleast a portion of the formation.

[0514] In some embodiments, a heat source as described above may beconfigured to substantially operate without a control and/or operatingsystem. The heat source may be configured to only require a power supplyfrom a power source such as an electric transformer. For example, aconductor-in-conduit heater and/or an elongated member heater mayinclude conductive materials that may be have a thermal property thatself-controls a heat output of the heat source. In this manner, theconductor-in-conduit heater and/or the elongated member heater may beconfigured to operate throughout a temperature range without externalcontrol. A conductive material such as stainless steel may be used inthe heat sources. Stainless steel may have a resistivity that increaseswith temperature, thus, providing a greater heat output at highertemperatures.

[0515] Leakage current of any of the heat sources described herein maybe monitored. For example, an increase in leakage current may showdeterioration in an insulated conductor heater. Voltage breakdown in theinsulated conductor heater may cause failure of the heat source.Furthermore, a current and voltage applied to any of the heat sourcesmay also be monitored. The current and voltage may be monitored toassess/indicate resistance in a heat source. The resistance in the heatsource may be configured to represent a temperature in the heat sourcesince the resistance of the heat source may be known as a function oftemperature. Another alternative method may include monitoring atemperature of a heat source with at least one thermocouple placed in orproximate to the heat source. In some embodiments, a control system maymonitor a parameter of the heat source. The control system may alterparameters of the heat source such that the heat source may provide adesired output such as heating rate and/or temperature increase.

[0516] In some embodiments, a thermowell may be disposed into an openingin a hydrocarbon containing formation that includes a heat source. Thethermowell may be disposed in an opening that may or may not have acasing. In the opening without a casing, the thermowell may includeappropriate metallurgy and thickness such that corrosion of thethermowell is substantially inhibited. A thermowell and temperaturelogging process, such as that described in U.S. Pat. No. 4,616,705issued to Stegemeier et al., which is incorporated by reference as iffully set forth herein, may be used to monitor temperature. Onlyselected wells may be equipped with thermowells to avoid expensesassociated with installing and operating temperature monitors at eachheat source.

[0517] In some embodiments, a heat source may be turned down and/or offafter an average temperature in a formation may have reached a selectedtemperature. Turning down and/or off the heat source may reduce inputenergy costs, substantially inhibit overheating of the formation, andallow heat to substantially transfer into colder regions of theformation.

[0518] Certain embodiments include providing heat to a first portion ofa hydrocarbon containing formation from one or more heat sources. Inaddition, certain embodiments may include producing formation fluidsfrom the first portion, and maintaining a second portion of theformation in a substantially unheated condition. The second portion maybe substantially adjacent to the first portion of the formation. In thismanner, the second portion may provide structural strength to theformation. Furthermore, heat may also be provided to a third portion ofthe formation. The third portion may be substantially adjacent to thesecond portion and/or laterally spaced from the first portion. Inaddition, formation fluids may be produced from the third portion of theformation. In this manner, a processed formation may have a pattern thatmay resemble, for example, a striped or checkerboard pattern withalternating heated and unheated portions.

[0519] Additional portions of the formation may also include suchalternating heated and unheated portions. In this manner, such patternedheating of a hydrocarbon containing formation may maintain structuralstrength within the formation. Maintaining structural strength within ahydrocarbon containing formation may substantially inhibit subsidence.Subsidence of a portion of the formation being processed may decrease apermeability of the processed portion due to compaction. In addition,subsidence may decrease the flow of fluids in the formation, which mayresult in a lower production of formation fluids.

[0520] A pyrolysis temperature range may depend on specific types ofhydrocarbons within the formation. A pyrolysis temperature range mayinclude temperatures, for example, between approximately 250° C. andabout 900° C. Alternatively, a pyrolysis temperature range may includetemperatures between about 250° C. to about 400° C. For example, amajority of formation fluids may be produced within a pyrolysistemperature range from about 250° C. to about 400° C. If a hydrocarboncontaining formation is heated throughout the entire pyrolysis range,the formation may produce only small amounts of hydrogen towards theupper limit of the pyrolysis range. After all of the available hydrogenhas been depleted, little fluid production from the formation wouldoccur.

[0521] Temperature (and average temperatures) within a heatedhydrocarbon containing formation may vary, depending on, for example,proximity to a heat source, thermal conductivity and thermal diffusivityof the formation, type of reaction occurring, type of hydrocarboncontaining formation, and the presence of water within the hydrocarboncontaining formation. A temperature within the hydrocarbon containingformation may be assessed using a numerical simulation model. Thenumerical simulation model may assess and/or calculate a subsurfacetemperature distribution. In addition, the numerical simulation modelmay include assessing various properties of a subsurface formation underthe assessed temperature distribution.

[0522] For example, the various properties of the subsurface formationmay include, but are not limited to, thermal conductivity of thesubsurface portion of the formation and permeability of the subsurfaceportion of the formation. The numerical simulation model may alsoinclude assessing various properties of a fluid formed within asubsurface formation under the assessed temperature distribution. Forexample, the various properties of a formed fluid may include, but arenot limited to, a cumulative volume of a fluid formed at a subsurface ofthe formation, fluid viscosity, fluid density, and a composition of thefluid formed at a subsurface of the formation. Such a simulation may beused to assess the performance of commercial-scale operation of asmall-scale field experiment as described herein. For example, aperformance of a commercial-scale development may be assessed based on,but not limited to, a total volume of product that may be produced froma commercial-scale operation.

[0523] In some embodiments, an in situ conversion process may increase atemperature or average temperature within a hydrocarbon containingformation. A temperature or average temperature increase (ΔT) in aspecified volume (V) of the hydrocarbon containing formation may beassessed for a given heat input rate (q) over time (t) by the followingequation:${\Delta \quad T} = \frac{\sum( {q*t} )}{C_{V}*\rho_{B}*V}$

[0524] In this equation, an average heat capacity of the formation(C_(v)) and an average bulk density of the formation (ρ_(B)) may beestimated or determined using one or more samples taken from thehydrocarbon containing formation.

[0525] In alternate embodiments, an in situ conversion process mayinclude heating a specified volume to a pyrolysis temperature or averagepyrolysis temperature. Heat input rate (q) during a time (t) required toheat the specified volume (V) to a desired temperature increase (ΔT) maybe determined or assessed using the following equation:Σq*t=ΔT*C_(V)*ρ_(B)*V. In this equation, an average heat capacity of theformation (C_(v)) and an average bulk density of the formation (ρ_(B))may be estimated or determined using one or more samples taken from thehydrocarbon containing formation.

[0526] It is to be understood that the above equations can be used toassess or estimate temperatures, average temperatures (e.g., overselected sections of the formation), heat input, etc. Such equations donot take into account other factors (such as heat losses) which wouldalso have some effect on heating and temperatures assessments. Howeversuch factors can ordinarily be addressed with correction factors, as iscommonly done in the art.

[0527] In some embodiments, a portion of a hydrocarbon containingformation may be heated at a heating rate in a range from about 0.1°C./day to about 50° C./day. Alternatively, a portion of a hydrocarboncontaining formation may be heated at a heating rate in a range of about0.1° C./day to about 10° C./day. For example, a majority of hydrocarbonsmay be produced from a formation at a heating rate within a range ofabout 0.1° C./day to about 10° C./day. In addition, a hydrocarboncontaining formation may be heated at a rate of less than about 0.7°C./day through a significant portion of a pyrolysis temperature range.The pyrolysis temperature range may include a range of temperatures asdescribed in above embodiments. For example, the heated portion may beheated at such a rate for a time greater than 50% of the time needed tospan the temperature range, more than 75% of the time needed to span thetemperature range, or more than 90% of the time needed to span thetemperature range.

[0528] A rate at which a hydrocarbon containing formation is heated mayaffect the quantity and quality of the formation fluids produced fromthe hydrocarbon containing formation. For example, heating at highheating rates, as is the case when a Fischer Assay is conducted, mayproduce a larger quantity of condensable hydrocarbons from a hydrocarboncontaining formation. The products of such a process, however, may be ofa significantly lower quality than when heating using heating rates lessthan about 10° C./day. Heating at a rate of temperature increase lessthan approximately 10° C./day may allow pyrolysis to occur within apyrolysis temperature range in which production of undesirable productsand tars may be reduced. In addition, a rate of temperature increase ofless than about 3° C./day may further increase the quality of theproduced condensable hydrocarbons by further reducing the production ofundesirable products and further reducing production of tars within ahydrocarbon containing formation.

[0529] In some embodiments, controlling temperature within a hydrocarboncontaining formation may involve controlling a heating rate within theformation. For example, controlling the heating rate such that theheating rate may be less than approximately 3° C./day may provide bettercontrol of a temperature within the hydrocarbon containing formation.

[0530] An in situ process for hydrocarbons may include monitoring a rateof temperature increase at a production well. A temperature within aportion of a hydrocarbon containing formation, however, may be measuredat various locations within the portion of the hydrocarbon containingformation. For example, an in situ process may include monitoring atemperature of the portion at a midpoint between two adjacent heatsources. The temperature may be monitored over time. In this manner, arate of temperature increase may also be monitored. A rate oftemperature increase may affect a composition of formation fluidsproduced from the formation. As such, a rate of temperature increase maybe monitored, altered and/or controlled, for example, to alter acomposition of formation fluids produced from the formation.

[0531] In some embodiments, a power (Pwr) required to generate a heatingrate (h) in a selected volume (V) of a hydrocarbon containing formationmay be determined by the following equation: Pwr=h*V*C_(V)*ρ_(B). Inthis equation, an average heat capacity of the hydrocarbon containingformation may be described as C_(V). The average heat capacity of thehydrocarbon containing formation may be a relatively constant value.Average heat capacity may be estimated or determined using one or moresamples taken from a hydrocarbon containing formation, or measured insitu using a thermal pulse test. Methods of determining average heatcapacity based on a thermal pulse test are described by I. Berchenko, E.Detournay, N. Chandler, J. Martino, and E. Kozak, “In-situ measurementof some thermoporoelastic parameters of a granite” in Poromechanics, ATribute to Maurice A. Biot, pages 545-550, Rotterdam, 1998 (Balkema),which is incorporated by reference as if fully set forth herein.

[0532] In addition, an average bulk density of the hydrocarboncontaining formation may be described as PB. The average bulk density ofthe hydrocarbon containing formation may be a relatively constant value.Average bulk density may be estimated or determined using one or moresamples taken from a hydrocarbon containing formation. In certainembodiments the product of average heat capacity and average bulkdensity of the hydrocarbon containing formation may be a relativelyconstant value (such product can be assessed in situ using a thermalpulse test). A determined power may be used to determine heat providedfrom a heat source into the selected volume such that the selectedvolume may be heated at a heating rate, h. For example, a heating ratemay be less than about 3° C./day, and even less than about 2° C./day. Inthis manner, a heating rate within a range of heating rates may bemaintained within the selected volume. It is to be understood that inthis context “power” is used to describe energy input per time. The formof such energy input may, however, vary as described herein (i.e.,energy may be provided from electrical resistance heaters, combustionheaters, etc.).

[0533] The heating rate may be selected based on a number of factorsincluding, but not limited to, the maximum temperature possible at thewell, a predetermined quality of formation fluids that may be producedfrom the formation, etc. A quality of hydrocarbon fluids may be definedby an API gravity of condensable hydrocarbons, by olefin content, by thenitrogen, sulfur and/or oxygen content, etc. In an embodiment, heat maybe provided to at least a portion of a hydrocarbon containing formationto produce formation fluids having an API gravity of greater than about20°. The API gravity may vary, however, depending on, for example, theheating rate and a pressure within the portion of the formation.

[0534] In some embodiments, subsurface pressure in a hydrocarboncontaining formation may correspond to the fluid pressure generatedwithin the formation. Heating hydrocarbons within a hydrocarboncontaining formation may generate fluids, for example, by pyrolysis. Thegenerated fluids may be vaporized within the formation. Fluids thatcontribute to the increase in pressure may include, but are not limitedto, fluids produced during pyrolysis and water vaporized during heating.The produced pyrolysis fluids may include, but are not limited to,hydrocarbons, water, oxides of carbon, ammonia, molecular nitrogen, andmolecular hydrogen. Therefore, as temperatures within a selected sectionof a heated portion of the formation increase, a pressure within theselected section may increase as a result of increased fluid generationand vaporization of water.

[0535] In some embodiments, pressure within a selected section of aheated portion of a hydrocarbon containing formation may vary dependingon, for example, depth, distance from a heat source, a richness of thehydrocarbons within the hydrocarbon containing formation, and/or adistance from a producer well. Pressure within a formation may bedetermined at a number of different locations, which may include but maynot be limited to, at a wellhead and at varying depths within awellbore. In some embodiments, pressure may be measured at a producerwell. In alternate embodiments, pressure may be measured at a heaterwell.

[0536] Heating of a hydrocarbon containing formation to a pyrolysistemperature range may occur before substantial permeability has beengenerated within the hydrocarbon containing formation. An initial lackof permeability may prevent the transport of generated fluids from apyrolysis zone within the formation. In this manner, as heat isinitially transferred from a heat source to a hydrocarbon containingformation, a fluid pressure within the hydrocarbon containing formationmay increase proximate to a heat source. Such an increase in fluidpressure may be caused by, for example, generation of fluids duringpyrolysis of at least some hydrocarbons in the formation. The increasedfluid pressure may be released, monitored, altered, and/or controlledthrough such a heat source. For example, the heat source may include avalve as described in above embodiments. Such a valve may be configuredto control a flow rate of fluids out of and into the heat source. Inaddition, the heat source may include an open hole configuration throughwhich pressure may be released.

[0537] Alternatively, pressure generated by expansion of pyrolysisfluids or other fluids generated in the formation may be allowed toincrease although an open path to the production well or any otherpressure sink may not yet exist in the formation. In addition, a fluidpressure may be allowed to increase to a lithostatic pressure. Fracturesin the hydrocarbon containing formation may form when the fluid pressureequals or exceeds the lithostatic pressure. For example, fractures mayform from a heat source to a production well. The generation offractures within the heated portion may reduce pressure within theportion due to the production of formation fluids through a productionwell. To maintain a selected pressure within the heated portion, a backpressure may be maintained at the production well.

[0538] Fluid pressure within a hydrocarbon containing formation may varydepending upon, for example, thermal expansion of hydrocarbons,generation of pyrolysis fluids, and withdrawal of generated fluids fromthe formation. For example, as fluids are generated within the formationa fluid pressure within the pores may increase. Removal of generatedfluids from the formation may decrease a fluid pressure within theformation.

[0539] In an embodiment, a pressure may be increased within a selectedsection of a portion of a hydrocarbon containing formation to a selectedpressure during pyrolysis. A selected pressure may be within a rangefrom about 2 bars absolute to about 72 bars absolute or, in someembodiments, 2 bars absolute to 36 bars absolute. Alternatively, aselected pressure may be within a range from about 2 bars absolute toabout 18 bars absolute. For example, in certain embodiments, a majorityof hydrocarbon fluids may be produced from a formation having a pressurewithin a range from about 2 bars absolute to about 18 bars absolute. Thepressure during pyrolysis may vary or be varied. The pressure may bevaried to alter and/or control a composition of a formation fluidproduced, to control a percentage of condensable fluid as compared tonon-condensable fluid, and/or to control an API gravity of fluid beingproduced. For example, decreasing pressure may result in production of alarger condensable fluid component, and the fluid may contain a largerpercentage of olefins, and vice versa.

[0540] In certain embodiments, pressure within a portion of ahydrocarbon containing formation will increase due to fluid generationwithin the heated portion. In addition, such increased pressure may bemaintained within the heated portion of the formation. For example,increased pressure within the formation may be maintained by bleedingoff a generated formation fluid through heat sources and/or bycontrolling the amount of formation fluid produced from the formationthrough production wells. Maintaining increased pressure within aformation inhibits formation subsidence. In addition, maintainingincreased pressure within a formation tends to reduce the required sizesof collection conduits that are used to transport condensablehydrocarbons. Furthermore, maintaining increased pressure within theheated portion may reduce and/or substantially eliminate the need tocompress formation fluids at the surface because the formation productswill usually be produced at higher pressure. Maintaining increasedpressure within a formation may also facilitate generation ofelectricity from produced non-condensable fluid. For example, theproduced non-condensable fluid may be passed through a turbine togenerate electricity.

[0541] Increased pressure in the formation may also be maintained toproduce more and/or improved formation fluids. In certain embodiments,significant amounts (e.g., a majority) of the formation fluids producedfrom a formation within the pyrolysis pressure range may includenon-condensable hydrocarbons. Pressure may be selectively increasedand/or maintained within the formation, and formation fluids can beproduced at or near such increased and/or maintained pressures. Aspressure within a formation is increased, formation fluids produced fromthe formation will, in many instances, include a larger portion ofnon-condensable hydrocarbons. In this manner, a significant amount(e.g., a majority) of the formation fluids produced at such a pressuremay include a lighter and higher quality condensable hydrocarbons thanformation fluids produced at a lower pressure.

[0542] In addition, a pressure may be maintained within a heated portionof a hydrocarbon containing formation to substantially inhibitproduction of formation fluids having carbon numbers greater than, forexample, about 25. For example, increasing a pressure within the portionof the hydrocarbon containing formation may increase a boiling point ofa fluid within the portion. Such an increase in the boiling point of afluid may substantially inhibit production of formation fluids havingrelatively high carbon numbers, and/or production of multi-ringhydrocarbon compounds, because such formation fluids tend to remain inthe formation as liquids until they crack.

[0543] In addition, increasing a pressure within a portion of ahydrocarbon containing formation may result in an increase in APIgravity of formation fluids produced from the formation. Higherpressures may increase production of shorter chain hydrocarbon fluids,which may have higher API gravity values.

[0544] In an embodiment, a pressure within a heated portion of theformation may surprisingly increase the quality of relatively highquality pyrolyzation fluids, the quantity of relatively high qualitypyrolyzation fluids, and/or vapor phase transport of the pyrolyzationfluids within the formation. Increasing the pressure often permitsproduction of lower molecular weight hydrocarbons since such lowermolecular weight hydrocarbons will more readily transport in the vaporphase in the formation. Generation of lower molecular weighthydrocarbons (and corresponding increased vapor phase transport) isbelieved to be due, in part, to autogenous generation and reaction ofhydrogen within a portion of the hydrocarbon containing formation. Forexample, maintaining an increased pressure may force hydrogen generatedin the heated portion into a liquid phase (e.g. by dissolving). Inaddition, heating the portion to a temperature within a pyrolysistemperature range may pyrolyze at least some of the hydrocarbons withinthe formation to generate pyrolyzation fluids in the liquid phase. Thegenerated components may include a double bond and/or a radical. H₂ inthe liquid phase may reduce the double bond of the generatedpyrolyzation fluids, thereby reducing a potential for polymerization ofthe generated pyrolyzation fluids. In addition, hydrogen may alsoneutralize radicals in the generated pyrolyzation fluids. Therefore, H₂in the liquid phase may substantially inhibit the generated pyrolyzationfluids from reacting with each other and/or with other compounds in theformation. In this manner, shorter chain hydrocarbons may enter thevapor phase and may be produced from the formation.

[0545] Increasing the formation pressure to increase the amount ofpyrolyzation fluids in the vapor phase may significantly reduce thepotential for coking within the selected section of the formation. Acoking reaction may occur in the liquid phase. Since many of thegenerated components may be transformed into short chain hydrocarbonsand may enter the vapor phase, coking within the selected section maydecrease.

[0546] Increasing the formation pressure to increase the amount ofpyrolyzation fluids in the vapor phase is also beneficial because doingso permits increased recovery of lighter (and relatively high quality)pyrolyzation fluids. In general, pyrolyzation fluids are more quicklyproduced, with less residuals, when such fluids are in the vapor phaserather than in the liquid phase. Undesirable polymerization reactionsalso tend to occur more frequently when the pyrolyzation fluids are inthe liquid phase instead of the vapor phase. In addition, whenpyrolyzation fluids are produced in the vapor phase, fewer productionwells/area are needed, thereby reducing project costs.

[0547] In an embodiment, a portion of a hydrocarbon containing formationmay be heated to increase a partial pressure of H₂. In some embodiments,an increased H₂ partial pressure may include H₂ partial pressures in arange from about 1 bar absolute to about 7 bars absolute. Alternatively,an increased H₂ partial pressure range may include H₂ partial pressuresin a range from about 5 bars absolute to about 7 bars absolute. Forexample, a majority of hydrocarbon fluids may be produced within a rangeof about 5 bars absolute to about 7 bars absolute. A range of H₂ partialpressures within the pyrolysis H₂ partial pressure range may vary,however, depending on, for example, a temperature and a pressure of theheated portion of the formation.

[0548] Maintaining a H₂ partial pressure within the formation of greaterthan atmospheric pressure may increase an API value of producedcondensable hydrocarbon fluids. For example, maintaining such a H₂partial pressure may increase an API value of produced condensablehydrocarbon fluids to greater than about 25 or, in some instances,greater than about 30. Maintaining such a H₂ partial pressure within aheated portion of a hydrocarbon containing formation may increase aconcentration of H₂ within the heated portion such that H₂ may beavailable to react with pyrolyzed components of the hydrocarbons.Reaction of H₂ with the pyrolyzed components of hydrocarbons may reducepolymerization of olefins into tars and other cross-linked, difficult toupgrade, products. Such products may have lower API gravity values.Therefore, production of hydrocarbon fluids having low API gravityvalues may be substantially inhibited.

[0549] A valve may be configured to maintain, alter, and/or control apressure within a heated portion of a hydrocarbon containing formation.For example, a heat source disposed within a hydrocarbon containingformation may be coupled to a valve. The valve may be configured torelease fluid from the formation through the heater source. In addition,a pressure valve may be coupled to a production well, which may bedisposed within the hydrocarbon containing formation. In someembodiments, fluids released by the valves may be collected andtransported to a surface unit for further processing and/or treatment.

[0550] An in situ conversion process for hydrocarbons may includeproviding heat to a portion of a hydrocarbon containing formation, andcontrolling a temperature, rate of temperature increase, and/or apressure within the heated portion. For example, a pressure within theheated portion may be controlled using pressure valves disposed within aheater well or a production well as described herein. A temperatureand/or a rate of temperature increase of the heated portion may becontrolled, for example, by altering an amount of energy supplied to oneor more heat sources.

[0551] Controlling a pressure and a temperature within a hydrocarboncontaining formation will, in most instances, affect properties of theproduced formation fluids. For example, a composition or a quality offormation fluids produced from the formation may be altered by alteringan average pressure and/or an average temperature in the selectedsection of the heated portion. The quality of the produced fluids may bedefined by a property which may include, but may not be limited to, APIgravity, percent olefins in the produced formation fluids, ethene toethane ratio, atomic hydrogen to carbon ratio, percent of hydrocarbonswithin produced formation fluids having carbon numbers greater than 25,total equivalent production (gas and liquid), total liquids production,and/or liquid yield as a percent of Fischer Assay. For example,controlling the quality of the produced formation fluids may includecontrolling average pressure and average temperature in the selectedsection such that the average assessed pressure in the selected sectionmay be greater than the pressure (p) as set forth in the form of thefollowing relationship for an assessed average temperature (T) in theselected section: $p = \exp^{\lbrack{\frac{A}{T} + B}\rbrack}$

[0552] where p is measured in psia (pounds per square inch absolute), Tis measured in degrees Kelvin, A and B are parameters dependent on thevalue of the selected property. An assessed average temperature may bedetermined as described herein.

[0553] The relationship given above may be rewritten such that thenatural log of pressure may be a linear function of an inverse oftemperature. This form of the relationship may be rewritten:ln(p)=A/T+B. In a plot of the absolute pressure as a function of thereciprocal of the absolute temperature, A is the slope and B is theintercept. The intercept B is defined to be the natural logarithm of thepressure as the reciprocal of the temperature approaches zero.Therefore, the slope and intercept values (A and B) of thepressure-temperature relationship may be determined from twopressure-temperature data points for a given value of a selectedproperty. The pressure-temperature data points may include an averagepressure within a formation and an average temperature within theformation at which the particular value of the property was, or may be,produced from the formation. For example, the pressure-temperature datapoints may be obtained from an experiment such as a laboratoryexperiment or a field experiment.

[0554] A relationship between the slope parameter, A, and a value of aproperty of formation fluids may be determined. For example, values of Amay be plotted as a function of values of a formation fluid property. Acubic polynomial may be fitted to these data. For example, a cubicpolynomial relationship such asA=a₁*(property)³+a₂*(property)²+a₃*(property)+a₄ may be fitted to thedata, where a₁, a₂, a₃, and a₄ are empirical constants that may describea relationship between the first parameter, A, and a property of aformation fluid. Alternatively, relationships having other functionalforms such as another order polynomial or a logarithmic function may befitted to the data. In this manner, a₁,a_(2, . . . , may be estimated from the results of the data fitting. Similarly, a relationship between the second parameter, B, and a value of a property of formation fluids may be determined. For example, values of B may be plotted as a function of values of a property of a formation fluid. A cubic polynomial may also be fitted to the data. For example, a cubic polynomial relationship such as B=b)₁*(property)³+b₂*(property)²+b₃*(property)+b₄ may be fitted to the data,where b₁, b₂, b₃, and b₄ are empirical constants that may describe arelationship between the parameter B, and the value of a property of aformation fluid. As such, b₁, b₂, b₃, and b₄ may be estimated fromresults of fitting the data. For example, TABLES 1a and 1b listestimated empirical constants determined for several properties of aformation fluid for Green River oil shale as described above. TABLE 1aPROPERTY A₁ A₂ a₃ a₄ API Gravity −0.738549 −8.893902 4752.182 −145484.6Ethene/Ethane Ratio −15543409 3261335 −303588.8 −2767.469 Weight Percentof Hydrocarbons 0.1621956 −8.85952 547.9571 −24684.9 Having a CarbonNumber Greater Than 25 Atomic H/C Ratio 2950062 −16982456 32584767−20846821 Liquid Production (gal/ton) 119.2978 −5972.91 96989 −524689Equivalent Liquid Production −6.24976 212.9383 −777.217 −39353.47(gal/ton) % Fischer Assay 0.5026013 −126.592 9813.139 −252736

[0555] TABLE 1b PROPERTY b₁ b₂ b₃ B₄ API Gravity 0.003843 −0.2794243.391071 96.67251 Ethene/Ethane Ratio −8974.317 2593.058 −40.7887423.31395 Weight Percent of −0.0005022 0.026258 −1.12695 44.49521Hydrocarbons Having a Carbon Number Greater Than 25 Atomic H/C Ratio790.0532 −4199.454 7328.572 −4156.599 Liquid Production −0.178088.914098 −144.999 793.2477 (gal/ton) Equivalent Liquid −0.03387 2.778804−72.6457 650.7211 Production (gal/ton) % Fischer Assay −0.00079010.196296 −15.1369 395.3574

[0556] To determine an average pressure and an average temperature thatmay be used to produce a formation fluid having a selected property, thevalue of the selected property and the empirical constants as describedabove may be used to determine values for the first parameter A, and thesecond parameter B, according to the following relationships:

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a ₄

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b ₄

[0557] For example, TABLES 2a-2g list estimated values for the parameterA, and approximate values for the parameter B, as determined for aselected property of a formation fluid as described above. TABLE 2a APIGravity 20 degrees −59906.9 83.46594 25 degrees 43778.5 66.85148 30degrees −30864.5 50.67593 35 degrees −21718.5 37.82131 40 degrees−16894.7 31.16965 45 degrees −16946.8 33.60297

[0558] TABLE 2b Ethene/Ethane Ratio 0.20 −57379 83.145 0.10 −1605627.652 0.05 −11736 21.986 0.01 −5492.8 14.234

[0559] TABLE 2c Weight Percent of Hydrocarbons Having a Carbon NumberGreater Than 25 25% −14206 25.123 20% −15972 28.442 15% −17912 31.80410% −19929 35.349 5% −21956 38.849 1% −24146 43.394

[0560] TABLE 2d Atomic H/C Ratio 1.7 −38360 60.531 1.8 −12635 23.989 1.9−7953.1 17.889 2.0 −6613.1 16.364

[0561] TABLE 2e Liquid Production (gal/ton) 14 gal/ton −10179 21.780 16gal/ton −13285 25.866 18 gal/ton −18364 32.882 20 gal/ton −19689 34.282

[0562] TABLE 2f Equivalent Liquid Production (gal/ton) 20 gal/ton −1972138.338 25 gal/ton −23350 42.052 30 gal/ton −39768.9 57.68

[0563] TABLE 2g % Fischer Assay 60% −11118 23.156 70% −13726 26.635 80%−20543 36.191 90% −28554 47.084

[0564] The determined values for the parameter A, and the parameter B,may be used to determine an average pressure in the selected section ofthe formation using an assessed average temperature, T, in the selectedsection. The assessed average temperature may be determined as describedherein. For example, an average pressure of the selected section may bedetermined by the relationship: p=exp[(A/T)+B], in which p is measuredin psia, and T is measured in degrees Kelvin. Alternatively, an averageabsolute pressure of the selected section, measured in bars, may bedetermined using the following relationship:P_(bars)=exp[(A/T)+B−2.6744]. In this manner, an average pressure withinthe selected section may be controlled such that an average pressurewithin the selected section is adjusted to the average pressure asdetermined above, in order to produce a formation fluid from theselected section having a selected property.

[0565] Alternatively, the determined values for the parameter A, and theparameter B, may be used to determine an average temperature in theselected section of the formation using an assessed average pressure, p,in the selected section. The assessed average pressure may be determinedas described herein. Therefore, using the relationship described above,an average temperature within the selected section may be controlled toapproximate the calculated average temperature in order to producehydrocarbon fluids having a selected property.

[0566] As described herein, a composition of formation fluids producedfrom a formation may be varied by altering at least one operatingcondition of an in situ conversion process for hydrocarbons. Inaddition, at least one operating condition may be determined by using acomputer-implemented method. For example, an operating condition mayinclude, but is not limited to, a pressure in the formation, atemperature in the formation, a heating rate of the formation, a powersupplied to a heat source, and/or a flow rate of a synthesis gasgenerating fluid. The computer-implemented method may include measuringat least one property of the formation. For example, measured propertiesmay include a thickness of a layer containing hydrocarbons, vitrinitereflectance, hydrogen content, oxygen content, moisture content,depth/width of the hydrocarbon containing formation, and otherproperties otherwise described herein.

[0567] At least one measured property may be inputted into a computerexecutable program. The program may be operable to determine at leastone operating condition from a measured property. In addition, at leastone property of selected formation fluids may be input into the program.For example, properties of selected formation fluids may include, butare not limited to, API gravity, olefin content, carbon numberdistribution, ethene to ethane ratio, and atomic carbon to hydrogenratio. The program may also be operable to determine at least oneoperating condition from a property of the selected formation fluids. Inthis manner, an operating condition of an in situ conversion process maybe altered to be approximate at least one determined operating conditionsuch that production of selected formation fluids from the formation mayincrease.

[0568] In an embodiment, a computer-implemented method may be used todetermine at least one property of a formation fluid that may beproduced from a hydrocarbon containing formation for a set of operatingconditions as a function of time. The method may include measuring atleast one property of the formation and providing at least the onemeasured property to a computer program as described herein. Inaddition, one or more sets of operating conditions may also be providedto the computer program. At least one of the operating conditions mayinclude, for example, a heating rate or a pressure. One or more sets ofoperating conditions may include currently used operating conditions (inan in situ conversion process) or operating conditions being consideredfor an in situ conversion process. The computer program may be operableto determine at least one property of a formation fluid that may beproduced by an in situ conversion process for hydrocarbons as a functionof time using at least one set of operating conditions and at least onemeasured property of the formation. Furthermore, the method may includecomparing a determined property of the fluid to a selected property. Inthis manner, if multiple determined properties are generated by thecomputer program, then the determined property that differs least from aselected property may be determined.

[0569] Formation fluid properties may vary depending on a location of aproduction well in the formation. For example, a location of aproduction well with respect to a location of a heat source in theformation may affect the composition of formation fluid produced from aformation. In addition, a distance between a production well and a heatsource in a formation may be varied to alter the composition offormation fluid produced from a formation. Decreasing a distance betweena production well and a heat source may increase a temperature at theproduction well. In this manner, a substantial portion of pyrolyzationfluids flowing through a production well may in some instances crack tonon-condensable compounds due to increased temperature at a productionwell. Therefore, a location of a production well with respect to a heatsource may be selected to increase a non-condensable gas fraction of theproduced formation fluids. In addition, a location of a production wellwith respect to a heat source may be selected such that anon-condensable gas fraction of produced formation fluids may be largerthan a condensable gas fraction of the produced formation fluids.

[0570] A carbon number distribution of a produced formation fluid mayindicate a quality of the produced formation fluid. In general,condensable hydrocarbons with low carbon numbers are considered to bemore valuable than condensable hydrocarbons having higher carbonnumbers. Low carbon numbers may include, for example, carbon numbersless than about 25. High carbon numbers may include carbon numbersgreater than about 25. In an embodiment, an in situ conversion processfor hydrocarbons may include providing heat to at least a portion of aformation and allowing heat to transfer such that heat may producepyrolyzation fluids such that a majority of the pyrolyzation fluids havecarbon numbers of less than approximately 25.

[0571] In an embodiment, an in situ conversion process for hydrocarbonsmay include providing heat to at least a portion of a hydrocarboncontaining formation at a rate sufficient to alter and/or controlproduction of olefins. For example, the process may include heating theportion at a rate to produce formation fluids having an olefin contentof less than about 10% by weight of condensable hydrocarbons of theformation fluids. Reducing olefin production may substantially reducecoating of a pipe surface by such olefins, thereby reducing difficultyassociated with transporting hydrocarbons through such piping. Reducingolefin production may also tend to inhibit polymerization ofhydrocarbons during pyrolysis, thereby increasing permeability in theformation and/or enhancing the quality of produced fluids (e.g., bylowering the carbon number distribution, increasing API gravity, etc.).

[0572] In some embodiments, however, the portion may be heated at a rateto selectively increase the olefin content of condensable hydrocarbonsin the produced fluids. For example, olefins may be separated from suchcondensable hydrocarbons and may be used to produce additional products.

[0573] In some embodiments, the portion may be heated at a rate toselectively increase the content of phenol and substituted phenols ofcondensable hydrocarbons in the produced fluids. For example, phenoland/or substituted phenols may be separated from such condensablehydrocarbons and may be used to produce additional products. Theresource may, in some embodiments, be selected to enhance production ofphenol and/or substituted phenols.

[0574] Hydrocarbons in the produced fluids may include a mixture of anumber of different components, some of which are condensable and someof which are not. The fraction of non-condensable hydrocarbons withinthe produced fluid may be altered and/or controlled by altering,controlling, and/or maintaining a temperature within a pyrolysistemperature range in a heated portion of the hydrocarbon containingformation. Additionally, the fraction of non-condensable hydrocarbonswithin the produced fluids may be altered and/or controlled by altering,controlling, and/or maintaining a pressure within the heated portion. Insome embodiments, surface facilities may be configured to separatecondensable and non-condensable hydrocarbons of a produced fluid.

[0575] In some embodiments, the non-condensable hydrocarbons mayinclude, but are not limited to, hydrocarbons having less than about 5carbon atoms, H₂, CO₂, ammonia, H₂S, N₂ and/or CO. In certainembodiments, non-condensable hydrocarbons of a fluid produced from aportion of a hydrocarbon containing formation may have a weight ratio ofhydrocarbons having carbon numbers from 2 through 4 (“C₂₋₄”hydrocarbons) to methane of greater than about 0.3, greater than about0.75, or greater than about 1 in some circumstances. For example,non-condensable hydrocarbons of a fluid produced from a portion of anoil shale or heavy hydrocarbon containing formation may have a weightratio of hydrocarbons having carbon numbers from 2 through 4, tomethane, of greater than approximately 1. In addition, non-condensablehydrocarbons of a fluid produced from a portion of a coal containingformation may have a weight ratio of hydrocarbons having carbon numbersfrom 2 through 4, to methane, of greater than approximately 0.3.

[0576] Such weight ratios of C₂₋₄ hydrocarbons to methane are believedto be beneficial as compared to similar weight ratios produced fromother formations. Such weight ratios indicate higher amounts ofhydrocarbons with 2, 3, and/or 4 carbons (e.g., ethane, propane, andbutane) than is normally present in gases produced from formations. Suchhydrocarbons are often more valuable. Production of hydrocarbons withsuch weight ratios is believed to be due to the conditions applied tothe formation during pyrolysis (e.g., controlled heating and/or pressureused in reducing environments, or at least non-oxidizing environments).It is believed that in such conditions longer chain hydrocarbons can bemore easily broken down to form substantially smaller (and in many casesmore saturated) compounds such as C₂₋₄ hydrocarbons. The C₂₋₄hydrocarbons to methane weight ratio may vary depending on, for example,a temperature of the heated portion and a heating rate of the heatedportion.

[0577] In certain embodiments, the API gravity of the hydrocarbons in afluid produced from a hydrocarbon containing formation may beapproximately 25 or above (e.g., 30, 40, 50, etc.).

[0578] Methane and at least a portion of ethane may be separated fromnon-condensable hydrocarbons in the produced fluid and may be utilizedas natural gas. A portion of propane and butane may be separated fromnon-condensable hydrocarbons of the produced fluid. In addition, theseparated propane and butane may be utilized as fuels or as feedstocksfor producing other hydrocarbons. A portion of the produced fluid havingcarbon numbers less than 4 may be reformed, as described herein, in theformation to produce additional H₂ and/or methane. In addition, ethane,propane, and butane may be separated from the non-condensablehydrocarbons and may be used to generate olefins.

[0579] The non-condensable hydrocarbons of fluid produced from ahydrocarbon containing formation may have a H₂ content of greater thanabout 5% by weight, greater than 10% by weight, or even greater than 15%by weight. The H₂ may be used, for example, as a fuel for a fuel cell,to hydrogenate hydrocarbon fluids in situ, and/or to hydrogenatehydrocarbon fluids ex situ. In addition, presence of H₂ within aformation fluid in a heated section of a hydrocarbon containingformation is believed to increase the quality of produced fluids. Incertain embodiments, the hydrogen to carbon atomic ratio of a producedfluid may be at least approximately 1.7 or above. For example, thehydrogen to carbon atomic ratio of a produced fluid may be approximately1.8, approximately 1.9, or greater.

[0580] The non-condensable hydrocarbons may include some hydrogensulfide. The non-condensable hydrocarbons may be treated to separate thehydrogen sulfide from other compounds in the non-condensablehydrocarbons. The separated hydrogen sulfide may be used to produce, forexample, sulfuric acid, fertilizer, and/or elemental sulfur.

[0581] In certain embodiments, fluid produced from a hydrocarboncontaining formation by an in situ conversion process may include carbondioxide. Carbon dioxide produced from the formation may be used, forexample, for enhanced oil recovery, as at least a portion of a feedstockfor production of urea, and/or may be reinjected into a hydrocarboncontaining formation for synthesis gas production and/or coal bedmethane production:

[0582] Fluid produced from a hydrocarbon containing formation by an insitu conversion process may include carbon monoxide. Carbon monoxideproduced from the formation may be used, for example, as a feedstock fora fuel cell, as a feedstock for a Fischer Tropsch process, as afeedstock for production of methanol, and/or as a feedstock forproduction of methane.

[0583] The condensable hydrocarbons of the produced fluids may beseparated from the fluids. In an embodiment, a condensable component mayinclude condensable hydrocarbons and compounds found in an aqueousphase. The aqueous phase may be separated from the condensablecomponent. The ammonia content of the total produced fluids may begreater than about 0.1% by weight of the fluid, greater than about 0.5%by weight of the fluid, and, in some embodiments, up to about 10% byweight of the produced fluids. The ammonia may be used to produce, forexample, urea.

[0584] Certain embodiments of a fluid may be produced in which amajority of hydrocarbons in the produced fluid have a carbon number ofless than approximately 25. Alternatively, less than about 15% by weightof the hydrocarbons in the condensable hydrocarbons have a carbon numbergreater than approximately 25. In some embodiments, less than about 5%by weight of hydrocarbons in the condensable hydrocarbons have a carbonnumber greater than approximately 25, and/or less than about 2% byweight of hydrocarbons in the condensable hydrocarbons have a carbonnumber greater than approximately 25.

[0585] In certain embodiments, a fluid produced from a formation (e.g.,a coal containing formation) may include oxygenated hydrocarbons. Forexample, condensable hydrocarbons of the produced fluid may include anamount of oxygenated hydrocarbons greater than about 5% by weight of thecondensable hydrocarbons. Alternatively, the condensable hydrocarbonsmay include an amount of oxygenated hydrocarbons greater than about 1.0%by weight of the condensable hydrocarbons. Furthermore, the condensablehydrocarbons may include an amount of oxygenated hydrocarbons greaterthan about 1.5% by weight of the condensable hydrocarbons or greaterthan about 2.0% by weight of the condensable hydrocarbons. In anembodiment, the oxygenated hydrocarbons may include, but are not limitedto, phenol and/or substituted phenols. In some embodiments, phenol andsubstituted phenols may have more economic value than other productsproduced from an in situ conversion process. Therefore, an in situconversion process may be utilized to produce phenol and/or substitutedphenols. For example, generation of phenol and/or substituted phenolsmay increase when a fluid pressure within the formation is maintained ata lower pressure.

[0586] In some embodiments, condensable hydrocarbons of a fluid producedfrom a hydrocarbon containing formation may also include olefins. Forexample, an olefin content of the condensable hydrocarbons may be in arange from about 0.1% by weight to about 15% by weight. Alternatively,an olefin content of the condensable hydrocarbons may also be within arange from about 0.1% by weight to about 5% by weight. Furthermore, anolefin content of the condensable hydrocarbons may also be within arange from about 0.1% by weight to about 2.5% by weight. An olefincontent of the condensable hydrocarbons may be altered and/or controlledby controlling a pressure and/or a temperature within the formation. Forexample, olefin content of the condensable hydrocarbons may be reducedby selectively increasing pressure within the formation, by selectivelydecreasing temperature within the formation, by selectively reducingheating rates within the formation, and/or by selectively increasinghydrogen partial pressures in the formation. In some embodiments, areduced olefin content of the condensable hydrocarbons may be preferred.For example, if a portion of the produced fluids is used to producemotor fuels, a reduced olefin content may be desired.

[0587] In alternate embodiments, a higher olefin content may bepreferred. For example, if a portion of the condensable hydrocarbons maybe sold, a higher olefin content may be preferred due to a high economicvalue of olefin products. In some embodiments, olefins may be separatedfrom the produced fluids and then sold and/or used as a feedstock forthe production of other compounds.

[0588] Non-condensable hydrocarbons of a produced fluid may also includeolefins. For example, an olefin content of the non-condensablehydrocarbons may be gauged using an ethene/ethane molar ratio. Incertain embodiments, the ethene/ethane molar ratio may range from about0.001 to about 0.15.

[0589] Fluid produced from a hydrocarbon containing formation mayinclude aromatic compounds. For example, the condensable hydrocarbonsmay include an amount of aromatic compounds greater than about 20% byweight or about 25% by weight of the condensable hydrocarbons.Alternatively, the condensable hydrocarbons may include an amount ofaromatic compounds greater than about 30% by weight of the condensablehydrocarbons. The condensable hydrocarbons may also include relativelylow amounts of compounds with more than two rings in them (e.g.,tri-aromatics or above). For example, the condensable hydrocarbons mayinclude less than about 1% by weight or less than about 2% by weight oftri-aromatics or above in the condensable hydrocarbons. Alternatively,the condensable hydrocarbons may include less than about 5% by weight oftri-aromatics or above in the condensable hydrocarbons.

[0590] In particular, in certain embodiments, asphaltenes (i.e., largemulti-ring aromatics that may be substantially soluble in hydrocarbons)make up less than about 0.1% by weight of the condensable hydrocarbons.For example, the condensable hydrocarbons may include an asphaltenecomponent of from about 0.0% by weight to about 0.1% by weight or, insome embodiments, less than about 0.3% by weight.

[0591] Condensable hydrocarbons of a produced fluid may also includerelatively large amounts of cycloalkanes. For example, the condensablehydrocarbons may include a cycloalkane component of from about 5% byweight to about 30% by weight of the condensable hydrocarbons.

[0592] In certain embodiments, the condensable hydrocarbons of a fluidproduced from a formation may include compounds containing nitrogen. Forexample, less than about 1% by weight (when calculated on an elementalbasis) of the condensable hydrocarbons may be nitrogen (e.g., typicallythe nitrogen may be in nitrogen containing compounds such as pyridines,amines, amides, carbazoles, etc.).

[0593] In certain embodiments, the condensable hydrocarbons of a fluidproduced from a formation may include compounds containing oxygen. Forexample, in certain embodiments (e.g., for oil shale and heavyhydrocarbons) less than about 1% by weight (when calculated on anelemental basis) of the condensable hydrocarbons may be oxygencontaining compounds (e.g., typically the oxygen may be in oxygencontaining compounds such as phenol, substituted phenols, ketones,etc.). In certain other embodiments, (e.g., for coal containingformations) between about 5% by weight and about 30% by weight of thecondensable hydrocarbons may typically include oxygen containingcompounds such as phenols, substituted phenols, ketones, etc. In someinstances, certain compounds containing oxygen (e.g., phenols) may bevaluable and, as such, may be economically separated from the producedfluid.

[0594] In certain embodiments, condensable hydrocarbons of the fluidproduced from a formation may include compounds containing sulfur. Forexample, less than about 1% by weight (when calculated on an elementalbasis) of the condensable hydrocarbons may be sulfur (e.g., typicallythe sulfur containing compounds may include compounds such asthiophenes, mercaptans, etc.).

[0595] Furthermore, the fluid produced from the formation may includeammonia (typically the ammonia may condense with water, if any, producedfrom the formation). For example, the fluid produced from the formationmay in certain embodiments include about 0.05% or more by weight ofammonia. Certain formations (e.g., coal and/or oil shale) may producelarger amounts of ammonia (e.g., up to about 10% by weight of the totalfluid produced may be ammonia).

[0596] In addition, a produced fluid from the formation may also includemolecular hydrogen (H₂). For example, the fluid may include a H₂ contentbetween about 10% to about 80% by volume of the non-condensablehydrocarbons.

[0597] In some embodiments, at least about 15% by weight of a totalorganic carbon content of hydrocarbons in the portion may be transformedinto hydrocarbon fluids.

[0598] A total potential amount of products that may be produced fromhydrocarbons may be determined by a Fischer Assay. The Fischer Assay isa standard method that involves heating a sample of hydrocarbons toapproximately 500° C. in one hour, collecting products produced from theheated sample, and quantifying the products. In an embodiment, a methodfor treating a hydrocarbon containing formation in situ may includeheating a section of the formation to yield greater than about 60% byweight of the potential amount of products from the hydrocarbons asmeasured by the Fischer Assay.

[0599] In certain embodiments, heating of the selected section of theformation may be controlled to pyrolyze at least about 20% by weight (orin some embodiments about 25% by weight) of the hydrocarbons within theselected section of the formation. Conversion of hydrocarbons within aformation may be limited to inhibit subsidence of the formation.

[0600] Heating at least a portion of a formation may cause at least someof the hydrocarbons within the portion to pyrolyze, thereby forminghydrocarbon fragments. The hydrocarbon fragments may be reactive and mayreact with other compounds in the formation and/or with otherhydrocarbon fragments produced by pyrolysis. Reaction of the hydrocarbonfragments with other compounds and/or with each other, however, mayreduce production of a selected product. A reducing agent in or providedto the portion of the formation during heating, however. may increaseproduction of the selected product. An example of a reducing agent mayinclude, but may not be limited to, H₂. For example, the reducing agentmay react with the hydrocarbon fragments to form a selected product.

[0601] In an embodiment, molecular hydrogen may be provided to theformation to create a reducing environment. A hydrogenation reactionbetween the molecular hydrogen and at least some of the hydrocarbonswithin a portion of the formation may generate heat. The generated heatmay be used to heat the portion of the formation. Molecular hydrogen mayalso be generated within the portion of the formation. In this manner,the generated H₂ may be used to hydrogenate hydrocarbon fluids within aportion of a formation.

[0602] For example, H₂ may be produced from a first portion of thehydrocarbon containing formation. The H₂ may be produced as a componentof a fluid produced from a first portion. For example, at least aportion of fluids produced from a first portion of the formation may beprovided to a second portion of the formation to create a reducingenvironment within the second portion. The second portion of theformation may be heated as described herein. In addition, produced H₂may be provided to a second portion of the formation. For example, apartial pressure of H₂ within the produced fluid may be greater than apyrolysis H₂ partial pressure, as measured at a well from which theproduced fluid may be produced.

[0603] For example, a portion of a hydrocarbon containing formation maybe heated in a reducing environment. The presence of a reducing agentduring pyrolysis of at least some of the hydrocarbons in the heatedportion may reduce (e.g., at least partially saturate) at least some ofthe pyrolyzed product. Reducing the pyrolyzed product may decrease aconcentration of olefins in hydrocarbon fluids. Reducing the pyrolysisproducts may improve the product quality of the hydrocarbon fluids.

[0604] An embodiment of a method for treating a hydrocarbon containingformation in situ may include generating H₂ and hydrocarbon fluidswithin the formation. In addition, the method may include hydrogenatingthe generated hydrocarbon fluids using the H₂ within the formation. Insome embodiments, the method may also include providing the generated H₂to a portion of the formation.

[0605] In an embodiment, a method of treating a portion of a hydrocarboncontaining formation may include heating the portion such that a thermalconductivity of a selected section of the heated portion increases. Forexample, porosity and permeability within a selected section of theportion may increase substantially during heating such that heat may betransferred through the formation not only by conduction but also byconvection and/or by radiation from a heat source. In this manner, suchradiant and convective transfer of heat may increase an apparent thermalconductivity of the selected section and, consequently, the thermaldiffusivity. The large apparent thermal diffusivity may make heating atleast a portion of a hydrocarbon containing formation from heat sourcesfeasible. For example, a combination of conductive, radiant, and/orconvective heating may accelerate heating. Such accelerated heating maysignificantly decrease a time required for producing hydrocarbons andmay significantly increase the economic feasibility of commercializationof an in situ conversion process. In a further embodiment, the in situconversion process for a hydrocarbon containing formation may alsoinclude providing heat to the heated portion to increase a thermalconductivity of a selected section to greater than about 0.5 W/(m ° C.)or about 0.6 W/(m ° C.).

[0606] In some embodiments, an in situ conversion process for a coalformation may increase the rank level of coal within a heated portion ofthe coal. The increase in rank level, as assessed by the vitrinitereflectance, of the coal may coincide with a substantial change of thestructure (e.g., molecular changes in the carbon structure) of the coal.The changed structure of the coal may have a higher thermalconductivity.

[0607] Thermal diffusivity within a hydrocarbon containing formation mayvary depending on, for example, a density of the hydrocarbon containingformation, a heat capacity of the formation, and a thermal conductivityof the formation. As pyrolysis occurs within a selected section, thehydrocarbon containing formation mass may be removed from the selectedsection. The removal of mass may include, but is not limited to, removalof water and a transformation of hydrocarbons to formation fluids. Forexample, a lower thermal conductivity may be expected as water isremoved from a coal containing formation. This effect may varysignificantly at different depths. At greater depths a lithostaticpressure may be higher, and may close certain openings (e.g., cleatsand/or fractures) in the coal. The closure of the coal openings mayincrease a thermal conductivity of the coal. In some embodiments, ahigher thermal conductivity may be observed due to a higher lithostaticpressure.

[0608] In some embodiments, an in situ conversion process may generatemolecular hydrogen during the pyrolysis process. In addition, pyrolysistends to increase the porosity/void spaces in the formation. Void spacesin the formation may contain hydrogen gas generated by the pyrolysisprocess. Hydrogen gas may have about six times the thermal conductivityof nitrogen or air. This may raise the thermal conductivity of theformation.

[0609] Certain embodiments described herein will in many instances beable to economically treat formations that were previously believed tobe uneconomical. Such treatment will be possible because of thesurprising increases in thermal conductivity and thermal diffusivitythat can be achieved with such embodiments. These surprising results areillustrated by the fact that prior literature indicated that certainhydrocarbon containing formations, such as coal, exhibited relativelylow values for thermal conductivity and thermal diffusivity when heated.For example, in government report No. 8364 by J. M. Singer and R. P. Tyeentitled “Thermal, Mechanical, and Physical Properties of SelectedBituminous Coals and Cokes,” U.S. Department of the Interior, Bureau ofMines (1979), the authors report the thermal conductivity and thermaldiffusivity for four bituminous coals. This government report includesgraphs of thermal conductivity and diffusivity that show relatively lowvalues up to about 400° C. (e.g., thermal conductivity is about 0.2 W/(m° C.) or below, and thermal diffusivity is below about 1.7×10⁻³ cm²/s).This government report states that “coals and cokes are excellentthermal insulators.”

[0610] In contrast, in certain embodiments described herein hydrocarboncontaining resources (e.g., coal) may be treated such that the thermalconductivity and thermal diffusivity are significantly higher (e.g.,thermal conductivity at or above about 0.5 W/(m ° C.) and thermaldiffusivity at or above 4.1×10⁻³ cm²/s) than would be expected based onprevious literature such as government report No. 8364. If treated asdescribed in certain embodiments herein, coal does not act as “anexcellent thermal insulator.” Instead, heat can and does transfer and/ordiffuse into the formation at significantly higher (and better) ratesthan would be expected according to the literature, therebysignificantly enhancing economic viability of treating the formation.

[0611] In an embodiment, heating a portion of a hydrocarbon containingformation in situ to a temperature less than an upper pyrolysistemperature may increase permeability of the heated portion. Forexample, permeability may increase due to formation of fractures withinthe heated portion caused by application of heat. As a temperature ofthe heated portion increases, water may be removed due to vaporization.The vaporized water may escape and/or be removed from the formation.Removal of water may also increase the permeability of the heatedportion. In addition, permeability of the heated portion may alsoincrease as a result of production of hydrocarbons from pyrolysis of atleast some of the hydrocarbons within the heated portion on amacroscopic scale. In an embodiment, a permeability of a selectedsection within a heated portion of a hydrocarbon containing formationmay be substantially uniform. For example, heating by conduction may besubstantially uniform, and thus a permeability created by conductiveheating may also be substantially uniform. In the context of this patent“substantially uniform permeability” means that the assessed (e.g.,calculated or estimated) permeability of any selected portion in theformation does not vary by more than a factor of 10 from the assessedaverage permeability of such selected portion.

[0612] Permeability of a selected section within the heated portion ofthe hydrocarbon containing formation may also rapidly increase while theselected section is heated by conduction. For example, permeability ofan impermeable hydrocarbon containing formation may be less than about0.1 millidarcy (9.9×10⁻¹⁷ m²) before treatment. In some embodiments,pyrolyzing at least a portion of a hydrocarbon containing formation mayincrease a permeability within a selected section of the portion togreater than about 10 millidarcy, 100 millidarcy, 1 Darcy, 10 Darcy, 20Darcy, or 50 Darcy. Therefore, a permeability of a selected section ofthe portion may increase by a factor of more than about 1,000, 10,000,or 100,000.

[0613] In some embodiments, superposition (e.g., overlapping) of heatfrom one or more heat sources may result in substantially uniformheating of a portion of a hydrocarbon containing formation. Sinceformations during heating will typically have temperature profilesthroughout them, in the context of this patent “substantially uniform”heating means heating such that the temperatures in a majority of thesection do not vary by more than 100° C. from the assessed averagetemperature in the majority of the selected section (volume) beingtreated.

[0614] Substantially uniform heating of the hydrocarbon containingformation may result in a substantially uniform increase inpermeability. For example, uniformly heating may generate a series ofsubstantially uniform fractures within the heated portion due to thermalstresses generated in the formation. Heating substantially uniformly maygenerate pyrolysis fluids from the portion in a substantiallyhomogeneous manner. Water removed due to vaporization and production mayresult in increased permeability of the heated portion. In addition tocreating fractures due to thermal stresses, fractures may also begenerated due to fluid pressure increase. As fluids are generated withinthe heated portion a fluid pressure within the heated portion may alsoincrease. As the fluid pressure approaches a lithostatic pressure of theheated portion, fractures may be generated. Substantially uniformheating and homogeneous generation of fluids may generate substantiallyuniform fractures within the heated portion. In some embodiments, apermeability of a heated section of a hydrocarbon containing formationmay not vary by more than a factor of about 10.

[0615] Removal of hydrocarbons due to treating at least a portion of ahydrocarbon containing formation, as described in any of the aboveembodiments, may also occur on a microscopic scale. Hydrocarbons may beremoved from micropores within the portion due to heating. Microporesmay be generally defined as pores having a cross-sectional dimension ofless than about 1000 Å. In this manner, removal of solid hydrocarbonsmay result in a substantially uniform increase in porosity within atleast a selected section of the heated portion. Heating the portion of ahydrocarbon containing formation, as described in any of the aboveembodiments, may substantially uniformly increase a porosity of aselected section within the heated portion. In the context of thispatent “substantially uniform porosity” means that the assessed (e.g.,calculated or estimated) porosity of any selected portion in theformation does not vary by more than about 25% from the assessed averageporosity of such selected portion.

[0616] Physical characteristics of a portion of a hydrocarbon containingformation after pyrolysis may be similar to those of a porous bed. Forexample, a portion of a hydrocarbon containing formation after pyrolysismay include particles having sizes of about several millimeters. Suchphysical characteristics may differ from physical characteristics of ahydrocarbon containing formation that may be subjected to injection ofgases that burn hydrocarbons in order to heat the hydrocarbons. Suchgases injected into virgin or fractured formations may tend to channeland may not be uniformly distributed throughout the formation. Incontrast, a gas injected into a pyrolyzed portion of a hydrocarboncontaining formation may readily and substantially uniformly contact thecarbon and/or hydrocarbons remaining in the formation. In addition,gases produced by heating the hydrocarbons may be transferred asignificant distance within the heated portion of the formation with aminimal pressure loss. Such transfer of gases may be particularlyadvantageous, for example, in treating a steeply dipping hydrocarboncontaining formation.

[0617] Synthesis gas may be produced from a portion of a hydrocarboncontaining formation containing, e.g., coal, oil shale, other kerogencontaining formations, heavy hydrocarbons (tar sands, etc.) and otherbitumen containing formations. The hydrocarbon containing formation maybe heated prior to synthesis gas generation to produce a substantiallyuniform, relatively high permeability formation. In an embodiment,synthesis gas production may be commenced after production of pyrolysisfluids has been substantially exhausted or becomes uneconomical.Alternately, synthesis gas generation may be commenced beforesubstantial exhaustion or uneconomical pyrolysis fluid production hasbeen achieved if production of synthesis gas will be more economicallyfavorable. Formation temperatures will usually be higher than pyrolysistemperatures during synthesis gas generation. Raising the formationtemperature from pyrolysis temperatures to synthesis gas generationtemperatures allows further utilization of heat applied to the formationto pyrolyze the formation. While raising a temperature of a formationfrom pyrolysis temperatures to synthesis gas temperatures, methaneand/or H₂ may be produced from the formation.

[0618] Producing synthesis gas from a formation from which pyrolyzationfluids have been previously removed allows a synthesis gas to beproduced that includes mostly H₂, CO, water and/or CO₂. Producedsynthesis gas, in certain embodiments, may have substantially nohydrocarbon component unless a separate source hydrocarbon stream isintroduced into the formation with or in addition to the synthesis gasproducing fluid. Producing synthesis gas from a substantially uniform,relatively high permeability formation that was formed by slowly heatinga formation through pyrolysis temperatures may allow for easyintroduction of a synthesis gas generating fluid into the formation, andmay allow the synthesis gas generating fluid to contact a relativelylarge portion of the formation. The synthesis gas generating fluid cando so because the permeability of the formation has been increasedduring pyrolysis and/or because the surface area per volume in theformation has increased during pyrolysis. The relatively large surfacearea (e.g., “contact area”) in the post-pyrolysis formation tends toallow synthesis gas generating reactions to be substantially atequilibrium conditions for C, H₂, CO, water and CO₂. Reactions in whichmethane is formed may, however, not be at equilibrium because they arekinetically limited. The relatively high, substantially uniformformation permeability may allow production wells to be spaced fartherapart than production wells used during pyrolysis of the formation.

[0619] A temperature of at least a portion of a formation that is usedto generate synthesis gas may be raised to a synthesis gas generatingtemperature (e.g., between about 400° C. and about 1200° C.). In someembodiments composition of produced synthesis gas may be affected byformation temperature, by the temperature of the formation adjacent tosynthesis gas production wells, and/or by residence time of thesynthesis gas components. A relatively low synthesis gas generationtemperature may produce a synthesis gas having a high H₂ to CO ratio,but the produced synthesis gas may also include a large portion of othergases such as water, CO₂, and methane. A relatively high formationtemperature may produce a synthesis gas having a H₂ to CO ratio thatapproaches 1, and the stream may include mostly (and in some casessubstantially only) H₂ and CO. If the synthesis gas generating fluid issubstantially pure steam, then the H₂ to CO ratio may approach 1 atrelatively high temperatures. At a formation temperature of about 700°C., the formation may produce a synthesis gas with a H₂ to CO ratio ofabout 2 at a certain pressure. The composition of the synthesis gastends to depend on the nature of the synthesis gas generating fluid.

[0620] Synthesis gas generation is generally an endothermic process.Heat may be added to a portion of a formation during synthesis gasproduction to keep formation temperature at a desired synthesis gasgenerating temperature or above a minimum synthesis gas generatingtemperature. Heat may be added to the formation from heat sources, fromoxidation reactions within the portion, and/or from introducingsynthesis gas generating fluid into the formation at a highertemperature than the temperature of the formation.

[0621] An oxidant may be introduced into a portion of the formation withsynthesis gas generating fluid. The oxidant may exothermically reactwith carbon within the portion of the formation to heat the formation.Oxidation of carbon within a formation may allow a portion of aformation to be economically heated to relatively high synthesis gasgenerating temperatures. The oxidant may also be introduced into theformation without synthesis gas generating fluid to heat the portion.Using an oxidant, or an oxidant and heat sources, to heat the portion ofthe formation may be significantly more favorable than heating theportion of the formation with only the heat sources. The oxidant may be,but is not limited to, air, oxygen, or oxygen enriched air. The oxidantmay react with carbon in the formation to produce CO₂ and/or CO. The useof air, or oxygen enriched air (i.e., air with an oxygen content greaterthan 21% by volume), to generate heat within the formation may cause asignificant portion of N₂ to be present in produced synthesis gas.Temperatures in the formation may be maintained below temperaturesneeded to generate oxides of nitrogen (NO_(x)), so that little or noNO_(x) compounds may be present in produced synthesis gas.

[0622] A mixture of steam and oxygen, or steam and air, may besubstantially continuously injected into a formation. If injection ofsteam and oxygen is used for synthesis gas production, the oxygen may beproduced on site by electrolysis of water utilizing direct currentoutput of a fuel cell. H₂ produced by the electrolysis of water may beused as a fuel stream for the fuel cell. O₂ produced by the electrolysisof water may be injected into the hot formation to raise a temperatureof the formation.

[0623] Heat sources and/or production wells within a formation forpyrolyzing and producing pyrolysis fluids from the formation may beutilized for different purposes during synthesis gas production. A wellthat was used as a heat source or a production well during pyrolysis maybe used as an injection well to introduce synthesis gas producing fluidinto the formation. A well that was used as a heat source or aproduction well during pyrolysis may be used as a production well duringsynthesis gas generation. A well that was used as a heat source or aproduction well during pyrolysis may be used as a heat source to heatthe formation during synthesis gas generation. Synthesis gas productionwells may be spaced further apart than pyrolysis production wellsbecause of the relatively high, substantially uniform permeability ofthe formation. Synthesis gas production wells may be heated torelatively high temperatures so that a portion of the formation adjacentto the production well is at a temperature that will produce a desiredsynthesis gas composition. Comparatively, pyrolysis fluid productionwells may not be heated at all, or may only be heated to a temperaturethat will inhibit condensation of pyrolysis fluid within the productionwell.

[0624] Synthesis gas may be produced from a dipping formation from wellsused during pyrolysis of the formation. As shown in FIG. 4, synthesisgas production wells 206 may be located above and down dip from aninjection well 208. Hot synthesis gas producing fluid may be introducedinto injection well 208. Hot synthesis gas fluid that moves down dip maygenerate synthesis gas that is produced through synthesis gas productionwells 206. Synthesis gas generating fluid that moves up dip may generatesynthesis gas in a portion of the formation that is at synthesis gasgenerating temperatures. A portion of the synthesis gas generating fluidand generated synthesis gas that moves up dip above the portion of theformation at synthesis gas generating temperatures may heat adjacentformation. The synthesis gas generating fluid that moves up dip maycondense, heat adjacent portions of formation, and flow downwardstowards or into a portion of the formation at synthesis gas generatingtemperature. The synthesis gas generating fluid may then generateadditional synthesis gas.

[0625] Synthesis gas generating fluid may be any fluid capable ofgenerating H₂ and CO within a heated portion of a formation. Synthesisgas generating fluid may include water. O₂, air, CO₂, hydrocarbonfluids, or combinations thereof. Water may be introduced into aformation as a liquid or as steam. Water may react with carbon in aformation to produce H₂, CO, and CO₂. CO₂ may react with hot carbon toform CO. Air and O₂ may be oxidants that react with carbon in aformation to generate heat and form CO₂, CO, and other compounds.Hydrocarbon fluids may react within a formation to form H₂, CO, CO₂,H₂O, coke, methane and/or other light hydrocarbons. Introducing lowcarbon number hydrocarbons (i.e., compounds with carbon numbers lessthan 5) may produce additional H₂ within the formation. Adding highercarbon number hydrocarbons to the formation may increase an energycontent of generated synthesis gas by having a significant methane andother low carbon number compounds fraction within the synthesis gas.

[0626] Water provided as a synthesis gas generating fluid may be derivedfrom numerous different sources. Water may be produced during apyrolysis stage of treating a formation. The water may include someentrained hydrocarbon fluids. Such fluid may be used as synthesis gasgenerating fluid. Water that includes hydrocarbons may advantageouslygenerate additional H₂ when used as a synthesis gas generating fluid.Water produced from water pumps that inhibit water flow into a portionof formation being subjected to an in situ conversion process mayprovide water for synthesis gas generation. A low rank kerogen resourceor hydrocarbons having a relatively high water content (i.e. greaterthan about 20% H₂O by weight) may generate a large amount of waterand/or CO₂ if subjected to an in situ conversion process. The water andCO₂ produced by subjecting a low rank kerogen resource to an in situconversion process may be used as a synthesis gas generating fluid.

[0627] Reactions involved in the formation of synthesis gas may include,but are not limited to:

C+H₂O

H₂+CO  (1)

C+2H₂O

2H₂+CO₂  (2)

C+CO₂

2CO  (3)

[0628] Thermodynamics allows the following reactions to proceed:

2C+2H₂O

CH₄+CO₂  (4)

C+2H₂

CH₄  (5)

[0629] However, kinetics of the reactions are slow in certainembodiments so that relatively low amounts of methane are formed atformation conditions from Reactions (4) and (5).

[0630] In the presence of oxygen, the following reaction may take placeto generate carbon dioxide and heat:

C+O₂→CO₂  (6)

[0631] Equilibrium gas phase compositions of coal in contact with steammay provide an indication of the compositions of components produced ina formation during synthesis gas generation. Equilibrium compositiondata for H₂, carbon monoxide, and carbon dioxide may be used todetermine appropriate operating conditions such as temperature that maybe used to produce a synthesis gas having a selected composition.Equilibrium conditions may be approached within a formation due to ahigh, substantially uniform permeability of the formation. Compositiondata obtained from synthesis gas production may in many instancesdeviate by less than 10% from equilibrium values.

[0632] In one embodiment, a composition of the produced synthesis gascan be changed by injecting additional components into the formationalong with steam. Carbon dioxide may be provided in the synthesis gasgenerating fluid to substantially inhibit production of carbon dioxideproduced from the formation during synthesis gas generation. The carbondioxide may shift the equilibrium of reaction (2) to the left, thusreducing the amount of carbon dioxide generated from formation carbon.The carbon dioxide may also react with carbon in the formation togenerate carbon monoxide. Carbon dioxide may be separated from thesynthesis gas and may be re-injected into the formation with thesynthesis gas generating fluid. Addition of carbon dioxide in thesynthesis gas generating fluid may, however, reduce the production ofhydrogen.

[0633]FIG. 29 depicts a schematic diagram of use of water recovered frompyrolysis fluid production being used to generate synthesis gas. Heatsource 801 with electric heater 803 produces pyrolysis fluid 807 fromfirst section 805 of the formation. Produced pyrolysis fluid 807 may besent to separator 809. Separator 809 may include a number of individualseparation units and processing units that produce aqueous stream 811,vapor stream 813, and hydrocarbon condensate stream 815. Aqueous stream811 from the separator 809 may be combined with synthesis gas generatingfluid 818 to form synthesis gas generating fluid 821. Synthesis gasgenerating fluid 821 may be provided to injection well 817 andintroduced to second portion 819 of the formation. Synthesis gas 823 maybe produced from synthesis gas production well 825.

[0634]FIG. 30 depicts a schematic diagram of an embodiment of a systemfor synthesis gas production in which carbon dioxide from producedsynthesis gas is injected into a formation. Synthesis gas 830 may beproduced from formation 832 through production well 834. Gas separationunit 836 may separate a portion of carbon dioxide from the synthesis gas830 to produce CO₂ stream 838 and remaining synthesis gas stream 840.The CO₂ stream 838 may be mixed with synthesis gas producing fluidstream 842 that is introduced into the formation 832 through injectionwell 837, and/or the CO₂ may be separately introduced into theformation. This may limit conversion of carbon within the formation toCO₂ and/or may increase an amount of CO generated within the formation.

[0635] Synthesis gas generating fluid may be introduced into a formationin a variety of different ways. Steam may be injected into a heatedhydrocarbon containing formation at a lowermost portion of the heatedformation. Alternatively, in a steeply dipping formation, steam may beinjected up dip with synthesis gas production down dip. The injectedsteam may pass through the remaining hydrocarbon containing formation toa production well. In addition, endothermic heat of reaction may beprovided to the formation with heat sources disposed along a path of theinjected steam. In alternate embodiments, steam may be injected at aplurality of locations along the hydrocarbon containing formation toincrease penetration of the steam throughout the formation. A line drivepattern of locations may also be utilized. The line drive pattern mayinclude alternating rows of steam injection wells and synthesis gasproduction wells.

[0636] At relatively low pressures, and temperatures below about 400°C., synthesis gas reactions are relatively slow. At relatively lowpressures, and temperatures between about 400° C. and about 700° C.,Reaction (2) tends to be the predominate reaction and the synthesis gascomposition is primarily hydrogen and carbon dioxide. At relatively lowpressures, and temperatures greater than about 700° C., Reaction (1)tends to be the predominate reaction and the synthesis gas compositionis primarily hydrogen and carbon monoxide.

[0637] Advantages of a lower temperature synthesis gas reaction mayinclude lower heat requirements, cheaper metallurgy and less endothermicreactions (especially when methane formation takes place). An advantageof a higher temperature synthesis gas reaction is that hydrogen andcarbon monoxide may be used as feedstock for other processes (e.g.,Fischer-Tropsch processes).

[0638] A pressure of the hydrocarbon containing formation may bemaintained at relatively high pressures during synthesis gas production.The pressure may range from atmospheric pressure to a lithostaticpressure of the formation. Higher formation pressures may allowgeneration of electricity by passing produced synthesis gas through aturbine. Higher formation pressures may allow for smaller collectionconduits to transport produced synthesis gas, and reduced downstreamcompression requirements on the surface.

[0639] In some embodiments, synthesis gas may be produced from a portionof a formation in a substantially continuous manner. The portion may beheated to a desired synthesis gas generating temperature. A synthesisgas generating fluid may be introduced into the portion. Heat may beadded to, or generated within, the portion of the formation duringintroduction of the synthesis gas generating fluid to the portion. Theadded heat compensates for the loss of heat due to the endothermicsynthesis gas reactions as well as heat losses to the top and bottomlayers, etc. In other embodiments, synthesis gas may be produced in asubstantially batch manner. The portion of the formation may be heated,or heat may be generated within the portion, to raise a temperature ofthe portion to a high synthesis gas generating temperature. Synthesisgas generating fluid may then be added to the portion until generationof synthesis gas reduces the temperature of the formation below atemperature that produces a desired synthesis gas composition.Introduction of the synthesis gas generating fluid may then be stopped.The cycle may be repeated by reheating the portion of the formation tothe high synthesis gas generating temperature and adding synthesis gasgenerating fluid after obtaining the high synthesis gas generatingtemperature. Composition of generated synthesis gas may be monitored todetermine when addition of synthesis gas generating fluid to theformation should be stopped.

[0640]FIG. 31 illustrates a schematic of an embodiment of a continuoussynthesis gas production system. FIG. 31 includes a formation with heatinjection wellbore 850 and heat injection wellbore 852. The wellboresmay be members of a larger pattern of wellbores placed throughout aportion of the formation. A portion of a formation may be heated tosynthesis gas generating temperatures by heating the formation with heatsources, by injecting an oxidizing fluid, or by a combination thereof.Oxidizing fluid 854, such as air or oxygen, and synthesis gas generatingfluid 856, such as steam, may be injected into wellbore 850. In oneembodiment, the ratio of oxygen to steam may be approximately 1:2 toapproximately 1:10, or approximately 1:3 to approximately 1:7 (e.g.,about 1:4).

[0641] In situ combustion of hydrocarbons may heat region 858 of theformation between wellbores 850 and 852. Injection of the oxidizingfluid may heat region 858 to a particular temperature range, forexample, between about 600° C. and about 700° C. The temperature mayvary, however, depending on a desired composition of the synthesis gas.An advantage of the continuous production method may be that thetemperature across region 858 may be substantially uniform andsubstantially constant with time once the formation has reachedsubstantial thermal equilibrium. Continuous production may alsoeliminate a need for use of valves to reverse injection directions on asubstantially frequent basis. Further, continuous production may reducetemperatures near the injections wells due to endothermic cooling fromthe synthesis gas reaction that may occur in the same region asoxidative heating. The substantially constant temperature may allow forcontrol of synthesis gas composition. Produced synthesis gas 860 mayexit continuously from wellbore 852.

[0642] In an embodiment, it may be desirable to use oxygen rather thanair as oxidizing fluid 854 in continuous production. If air is used,nitrogen may need to be separated from the synthesis gas. The use ofoxygen as oxidizing fluid 854 may increase a cost of production due tothe cost of obtaining substantially pure oxygen. The cryogenic nitrogenby-product obtained from an air separation plant used to produce therequired oxygen may, however, be used in a heat exchanger to condensehydrocarbons from a hot vapor stream produced during pyrolysis ofhydrocarbons. The pure nitrogen may also be used for ammonia production.

[0643]FIG. 32 illustrates a schematic of an embodiment of a batchproduction of synthesis gas in a hydrocarbon containing formation.Wellbore 870 and wellbore 872 may be located within a portion of theformation. The wellbores may be members of a larger pattern of wellboresthroughout the portion of the formation. Oxidizing fluid 874, such asair or oxygen, may be injected into wellbore 870. Oxidation ofhydrocarbons may heat region 876 of a formation between wellbores 870and 872. Injection of air or oxygen may continue until an averagetemperature of region 876 is at a desired temperature (e.g., betweenabout 900° C. and about 1000° C.). Higher or lower temperatures may alsobe developed. A temperature gradient may be formed in region 876 betweenwellbore 870 and wellbore 872. The highest temperature of the gradientmay be located proximate to the injection wellbore 870.

[0644] When a desired temperature has been reached, or when oxidizingfluid has been injected for a desired period of time, oxidizing fluidinjection may be lessened and/or ceased. A synthesis gas generatingfluid 877, such as steam or water, may be injected into the injectionwellbore 872 to produce synthesis gas. A back pressure of the injectedsteam or water in the injection wellbore may force the synthesis gasproduced and un-reacted steam across region 876. A decrease in averagetemperature of region 876 caused by the endothermic synthesis gasreaction may be partially offset by the temperature gradient in region876 in a direction indicated by arrow 878. Product stream 880 may beproduced through heat source wellbore 870. If the composition of theproduct deviates substantially from a desired composition, then steaminjection may cease, and air or oxygen injection may be reinitiated.

[0645] In one embodiment, synthesis gas of a selected composition may beproduced by blending synthesis gas produced from different portions ofthe formation. A first portion of a formation may be heated by one ormore heat sources to a first temperature sufficient to allow generationof synthesis gas having a H₂ to carbon monoxide ratio of less than theselected H₂ to carbon monoxide ratio (e.g., about 1 or 2). A firstsynthesis gas generating fluid may be provided to the first portion togenerate a first synthesis gas. The first synthesis gas may be producedfrom the formation. A second portion of the formation may be heated byone or more heat sources to a second temperature sufficient to allowgeneration of synthesis gas having a H₂ to carbon monoxide ratio ofgreater than the selected H₂ to carbon monoxide ratio (e.g., a ratio of3 or more). A second synthesis gas generating fluid may be provided tothe second portion to generate a second synthesis gas. The secondsynthesis gas may be produced from the formation. The first synthesisgas may be blended with the second synthesis gas to produce a blendsynthesis gas having a desired H₂ to carbon monoxide ratio.

[0646] The first temperature may be substantially different than thesecond temperature. Alternatively, the first and second temperatures maybe approximately the same temperature. For example, a temperaturesufficient to allow generation of synthesis gas having differentcompositions may vary depending on compositions of the first and secondportions and/or prior pyrolysis of hydrocarbons within the first andsecond portions. The first synthesis gas generating fluid may havesubstantially the same composition as the second synthesis gasgenerating fluid. Alternatively, the first synthesis gas generatingfluid may have a different composition than the second synthesis gasgenerating fluid. Appropriate first and second synthesis generatingfluids may vary depending upon, for example, temperatures of the firstand second portions, compositions of the first and second portions, andprior pyrolysis of hydrocarbons within the first and second portions.

[0647] In addition, synthesis gas having a selected ratio of H₂ tocarbon monoxide may be obtained by controlling the temperature of theformation. In one embodiment, the temperature of an entire portion orsection of the formation may be controlled to yield synthesis gas with aselected ratio. Alternatively, the temperature in or proximate to asynthesis gas production well may be controlled to yield synthesis gaswith the selected ratio.

[0648] In one embodiment, synthesis gas having a selected ratio of H₂ tocarbon monoxide may be obtained by treating produced synthesis gas atthe surface. First, the temperature of the formation may be controlledto yield synthesis gas with a ratio different than a selected ratio. Forexample, the formation may be maintained at a relatively hightemperature to generate a synthesis gas with a relatively low H₂ tocarbon monoxide ratio (e.g., the ratio may approach 1 under certainconditions). Some or all of the produced synthesis gas may then beprovided to a shift reactor (shift process) at the surface. Carbonmonoxide reacts with water in the shift process to produce H₂ and carbondioxide. Therefore, the shift process increases the H₂ to carbonmonoxide ratio. The carbon dioxide may then be separated to obtain asynthesis gas having a selected H₂ to carbon monoxide ratio.

[0649] In one embodiment, produced synthesis gas 918 may be used forproduction of energy. In FIG. 33, treated gases 920 may be routed fromtreatment section 900 to energy generation unit 902 for extraction ofuseful energy. Energy may be extracted from the combustible gasesgenerally by oxidizing the gases to produce heat and converting aportion of the heat into mechanical and/or electrical energy.Alternatively, energy generation unit 902 may include a fuel cell thatproduces electrical energy. In addition, energy generation unit 902 mayinclude, for example, a molten carbonate fuel cell or another type offuel cell, a turbine, a boiler firebox, or a down hole gas heater.Produced electrical energy 904 may be supplied to power grid 906. Aportion of the produced electricity 908 may be used to supply energy toelectrical heating elements 910 that heat formation 912.

[0650] In one embodiment, energy generation unit 902 may be a boilerfirebox. A firebox may include a small refractory-lined chamber, builtwholly or partly in the wall of a kiln, for combustion of fuel. Air oroxygen 914 may be supplied to energy generation unit 902 to oxidize theproduced synthesis gas. Water 916 produced by oxidation of the synthesisgas may be recycled to the formation to produce additional synthesisgas.

[0651] The produced synthesis gas may also be used as a fuel in downhole gas heaters. Down hole gas heaters, such as a flameless combustoras disclosed herein, may be configured to heat a hydrocarbon containingformation. In this manner, a thermal conduction process may besubstantially self-reliant and/or may substantially reduce or eliminatea need for electricity. Because flameless combustors may have a thermalefficiency approaching 90%, an amount of carbon dioxide released to theenvironment may be less than an amount of carbon dioxide released to theenvironment from a process using fossil-fuel generated electricity toheat the hydrocarbon containing formation.

[0652] Carbon dioxide may be produced by both pyrolysis and synthesisgas generation. Carbon dioxide may also be produced by energy generationprocesses and/or combustion processes. Net release of carbon dioxide tothe atmosphere from an in situ conversion process for hydrocarbons maybe reduced by utilizing the produced carbon dioxide and/or by storingcarbon dioxide within the formation. For example, a portion of carbondioxide produced from the formation may be utilized as a flooding agentor as a feedstock for producing chemicals.

[0653] In one embodiment, the energy generation process may produce areduced amount of emissions by sequestering carbon dioxide producedduring extraction of useful energy. For example, emissions from anenergy generation process may be reduced by storing an amount of carbondioxide within a hydrocarbon containing formation. The amount of storedcarbon dioxide may be approximately equivalent to that in an exit streamfrom the formation.

[0654]FIG. 33 illustrates a reduced emission energy process. Carbondioxide 928 produced by energy generation unit 902 may be separated fromfluids exiting the energy generation unit. Carbon dioxide may beseparated from H₂ at high temperatures by using a hot palladium filmsupported on porous stainless steel or a ceramic substrate, or hightemperature pressure swing adsorption. The carbon dioxide may besequestered in spent hydrocarbon containing formation 922, injected intooil producing fields 924 for enhanced oil recovery by improving mobilityand production of oil in such fields, sequestered into a deephydrocarbon containing formation 926 containing methane by adsorptionand subsequent desorption of methane, or re-injected 928 into a sectionof the formation through a synthesis gas production well to producecarbon monoxide. Carbon dioxide leaving the energy generation unit maybe sequestered in a dewatered methane reservoir. The water for synthesisgas generation may come from dewatering a methane reservoir. Additionalmethane can also be produced by alternating carbon dioxide and nitrogen.An example of a method for sequestering carbon dioxide is illustrated inU.S. Pat. No. 5,566,756 to Chaback et al., which is incorporated byreference as if fully set forth herein. Additional energy may beutilized by removing heat from the carbon dioxide stream leaving theenergy generation unit.

[0655] In one embodiment, it may be desirable to cool a hot spentformation before sequestration of carbon dioxide. For example, a higherquantity of carbon dioxide may be adsorbed in a coal formation at lowertemperatures. In addition, cooling a formation may strengthen aformation. The spent formation may be cooled by introducing water intothe formation. The steam produced may be removed from the formation. Thegenerated steam may be used for any desired process. For example, thesteam may be provided to an adjacent portion of a formation to heat theadjacent portion or to generate synthesis gas.

[0656] In one embodiment, a spent hydrocarbon containing formation maybe mined. The mined material may in some embodiments be used formetallurgical purposes such as a fuel for generating high temperaturesduring production of steel. Pyrolysis of a coal containing formation maysubstantially increase a rank of the coal. After pyrolysis, the coal maybe substantially transformed to a coal having characteristics ofanthracite. A spent hydrocarbon containing formation may have athickness of 30 m or more. Anthracite coal seams, which are typicallymined for metallurgical uses, may be only about one meter in thickness.

[0657]FIG. 34 illustrates an embodiment in which fluid produced frompyrolysis may be separated into a fuel cell feed stream and fed into afuel cell to produce electricity. The embodiment may include carboncontaining formation 940 with producing well 942 configured to producesynthesis gas and heater well 944 with electric heater 946 configured toproduced pyrolysis fluid 948. In one embodiment, pyrolysis fluid mayinclude H₂ and hydrocarbons with carbon numbers less than 5. Pyrolysisfluid 948 produced from heater well 944 may be fed to gas membraneseparation system 950 to separate H₂ and hydrocarbons with carbonnumbers less than 5. Fuel cell feed stream 952, which may besubstantially composed of H₂, may be fed into fuel cell 954. Air feedstream 956 may be fed into fuel cell 954. Nitrogen stream 958 may bevented from fuel cell 954. Electricity 960 produced from the fuel cellmay be routed to a power grid. Electricity 962 may also be used to powerelectric heaters 946 in heater wells 944. Carbon dioxide 965 may beinjected into formation 940.

[0658] Hydrocarbons having carbon numbers of 4, 3, and 1 typically havefairly high market values. Separation and selling of these hydrocarbonsmay be desirable. Typically ethane may not be sufficiently valuable toseparate and sell in some markets. Ethane may be sent as part of a fuelstream to a fuel cell or ethane may be used as a hydrocarbon fluidcomponent of a synthesis gas generating fluid. Ethane may also be usedas a feedstock to produce ethene. In some markets, there may be nomarket for any hydrocarbons having carbon numbers less than 5. In such asituation, all of the hydrocarbon gases produced during pyrolysis may besent to fuel cells or be used as hydrocarbon fluid components of asynthesis gas generating fluid.

[0659] Pyrolysis fluid 964, which may be substantially composed ofhydrocarbons with carbon numbers less than 5, may be injected intoformation 940. When the hydrocarbons contact the formation, hydrocarbonsmay crack within the formation to produce methane, H₂, coke, and olefinssuch as ethene and propylene. In one embodiment, the production ofolefins may be increased by heating the temperature of the formation tothe upper end of the pyrolysis temperature range and by injectinghydrocarbon fluid at a relatively high rate. In this manner, residencetime of the hydrocarbons in the formation may be reduced anddehydrogenated hydrocarbons may tend to form olefins rather thancracking to form H₂ and coke. Olefin production may also be increased byreducing formation pressure.

[0660] In one embodiment, electric heater 946 may be a flamelessdistributed combustor. At least a portion of H₂ produced from theformation may be used as fuel for the flameless distributed combustor.

[0661] In addition, in some embodiments, heater well 944 may heat theformation to a synthesis gas generating temperature range. Pyrolysisfluid 964, which may be substantially composed of hydrocarbons withcarbon numbers less than 5, may be injected into the formation 940. Whenthe hydrocarbons contact the formation, the hydrocarbons may crackwithin the formation to produce methane, H₂, and coke.

[0662]FIG. 35 depicts an embodiment of a synthesis gas generatingprocess from hydrocarbon containing formation 976 with flamelessdistributed combustor 996. Synthesis gas 980 produced from productionwell 978 may be fed into gas separation plant 984 where carbon dioxide986 may be separated from synthesis gas 980. First portion 990 of carbondioxide may be routed to a formation for sequestration. Second portion992 of carbon dioxide may also be injected into the formation withsynthesis gas generating fluid. Portion 993 of synthesis gas 988 may befed to heater well 994 for combustion in distributed burner 996 toproduce heat for the formation. Portion 998 of synthesis gas 988 may befed to fuel cell 1000 for the production of electricity. Electricity1002 may be routed to a power grid. Steam 1004 produced in the fuel celland steam 1006 produced from combustion in the distributed burner may befed to the formation for generation of synthesis gas.

[0663] In one embodiment, carbon dioxide generated with pyrolysis fluidsas described herein may be sequestered in a hydrocarbon containingformation. FIG. 36 illustrates in situ pyrolysis in hydrocarboncontaining formation 1020. Heater well 1022 with electric heater 1024may be disposed in formation 1020. Pyrolysis fluids 1026 may be producedfrom formation 1020 and fed into gas separation unit 1028 where carbondioxide 1030 may be separated from pyrolysis fluids 1032. Portion 1034of carbon dioxide 1030 may be stored in formation 1036. The carbondioxide may be sequestered in spent hydrocarbon containing formation1038, injected into oil producing fields 1040 for enhanced oil recovery,or sequestered into coal bed 1042. Alternatively, carbon dioxide mayalso be re-injected 1044 into a section of formation 1020 through asynthesis gas production well to produce carbon monoxide. At least aportion of electricity 1035 may be used to power one or more electricheaters.

[0664] In one embodiment, fluid produced from pyrolysis of at least somehydrocarbons in a formation may be fed into a reformer to producesynthesis gas. The synthesis gas may be fed into a fuel cell to produceelectricity. In addition, carbon dioxide generated by the fuel cell maybe sequestered to reduce an amount of emissions generated by theprocess.

[0665] As shown in FIG. 37, heater well 1060 may be located withinhydrocarbon containing formation 1062. Additional heater wells may alsobe located within the formation. Heater well 1060 may include electricheater 1064. Pyrolysis fluid 1066 produced from the formation may be fedto a reformer, such as steam reformer 1068, to produce synthesis gas1070. A portion of the pyrolysis products may be used as fuel in thereformer. Steam reformer 1068 may include a catalyst material thatpromotes the reforming reaction and a burner to supply heat for theendothermic reforming reaction. A steam source may be connected to thereformer section to provide steam for the reforming reaction. The burnermay operate at temperatures well above that required by the reformingreaction and well above the operating temperatures of fuel cells. Assuch, it may be desirable to operate the burner as a separate unitindependent of the fuel cell.

[0666] Alternatively, a reformer may include multiple tubes that may bemade of refractory metal alloys. Each tube may include a packed granularor pelletized material having a reforming catalyst as a surface coating.A diameter of the tubes may vary from between about 9 cm and about 16cm, and the heated length of the tube may normally be between about 6 mand about 12 m. A combustion zone may be provided external to the tubes,and may be formed in the burner. A surface temperature of the tubes maybe maintained by the burner at a temperature of about 900° C. to ensurethat the hydrocarbon fluid flowing inside the tube is properly catalyzedwith steam at a temperature between about 500° C. and about 700° C. Atraditional tube reformer may rely upon conduction and convection heattransfer within the tube to distribute heat for reforming.

[0667] In addition, hydrocarbon fluids, such as pyrolysis fluids, may bepre-processed prior to being fed to a reformer. The reformer may beconfigured to transform the pyrolysis fluids into simpler reactantsprior to introduction to a fuel cell. For example, pyrolysis fluids maybe pre-processed in a desulfurization unit. Subsequent topre-processing, the pyrolysis fluids may be provided to a reformer and ashift reactor to produce a suitable fuel stock for a H₂ fueled fuelcell.

[0668] The synthesis gas produced by the reformer may include any of thecomponents described above, such as methane. The produced synthesis gas1070 may be fed to fuel cell 1072. A portion of electricity 1074produced by the fuel cell may be sent to a power grid. In addition, aportion of electricity 1076 may be used to power electric heater 1064.Carbon dioxide 1078 exiting the fuel cell may be routed to sequestrationarea 1080.

[0669] Alternatively, in one embodiment, pyrolysis fluids 1066 producedfrom the formation may be fed to reformer 1068 that produces carbondioxide stream 1082 and H₂ stream 1070. For example, the reformer mayinclude a flameless distributed combustor for a core, and a membrane.The membrane may allow only H₂ to pass through the membrane resulting inseparation of the H₂ and carbon dioxide. The carbon dioxide may berouted to sequestration area 1080.

[0670] Synthesis gas produced from a formation may be converted toheavier condensable hydrocarbons. For example, a Fischer-Tropschhydrocarbon synthesis process may be used for conversion of synthesisgas. A Fischer-Tropsch process may include converting synthesis gas tohydrocarbons. The process may use elevated temperatures, normal orelevated pressures, and a catalyst, such as magnetic iron oxide or acobalt catalyst. Products produced from a Fischer-Tropsch process mayinclude hydrocarbons having a broad molecular weight distribution andmay include branched and unbranched paraffins. Products from aFischer-Tropsch process may also include considerable quantities ofolefins and oxygen-containing organic compounds. An example of aFischer-Tropsch reaction may be illustrated by the following:

(n+2)CO+(2n+5)H₂→CH₃(—CH₂—)n CH₃+(n+2)H₂O  (7)

[0671] A hydrogen to carbon monoxide ratio for synthesis gas used as afeed gas for a Fischer-Tropsch reaction may be about 2:1. In certainembodiments the ratio may range from approximately 1.8:1 to 2.2:1.Higher or lower ratios may be accommodated by certain Fischer-Tropschsystems.

[0672]FIG. 38 illustrates a flowchart of a Fischer-Tropsch process thatuses synthesis gas produced from a hydrocarbon containing formation as afeed stream. Hot formation 1090 may be used to produce synthesis gashaving a H₂ to CO ratio of approximately 2:1. The proper ratio may beproduced by operating synthesis production wells at approximately 700°C., or by blending synthesis gas produced from different sections offormation to obtain a synthesis gas having approximately a 2:1 H₂ to COratio. Synthesis gas generating fluid 1092 may be fed into the hotformation 1090 to generate synthesis gas. H₂ and CO may be separatedfrom the synthesis gas produced from the hot formation 1090 to form feedstream 1094. Feed stream 1094 may be sent to Fischer-Tropsch plant 1096.Feed stream 1094 may supplement or replace synthesis gas 1098 producedfrom catalytic methane reformer 1100.

[0673] Fischer-Tropsch plant 1096 may produce wax feed stream 1102. TheFischer-Tropsch synthesis process that produces wax feed stream 1102 isan exothermic process. Steam 1104 may be generated during theFischer-Tropsch process. Steam 1104 may be used as a portion ofsynthesis gas generating fluid 1092.

[0674] Wax feed stream 1102 produced from Fischer-Tropsch plant 1096 maybe sent to hydrocracker 1106. The hydrocracker may produce productstream 1108. The product stream may include diesel, jet fuel, and/ornaphtha products. Examples of methods for conversion of synthesis gas tohydrocarbons in a Fischer-Tropsch process are illustrated in U.S. Pat.No. 4,096,163 to Chang et al., U.S. Pat. No. 6,085,512 to Agee et al.,and U.S. Pat. No. 6,172,124 to Wolflick et al., which are incorporatedby reference as if fully set forth herein.

[0675]FIG. 39 depicts an embodiment of in situ synthesis gas productionintegrated with a Shell Middle Distillates Synthesis (SMDS)Fischer-Tropsch and wax cracking process. An example of a SMDS processis illustrated in U.S. Pat. No. 4,594,468 to Minderhoud, and isincorporated by reference as if fully set forth herein. A middledistillates hydrocarbon mixture may also be produced from producedsynthesis gas using the SMDS process as illustrated in FIG. 39. Middledistillates may designate hydrocarbon mixtures with a boiling pointrange that may correspond substantially with that of kerosene and gasoil fractions obtained in a conventional atmospheric distillation ofcrude oil material. The middle distillate boiling point range mayinclude temperatures between about 150° C. and about 360° C., with afractions boiling point between about 200° C. and about 360° C., and maybe referred to as gas oil. FIG. 39 depicts synthesis gas 1120, having aH₂ to carbon monoxide ratio of about 2:1, that may exit production well1128 and may be fed into SMDS plant 1122. In certain embodiments theratio may range from approximately 1.8:1 to 2.2:1. Products of the SMDSplant include organic liquid product 1124 and steam 1126. Steam 1126 maybe supplied to injection wells 1127. In this manner, steam may be usedas a feed for synthesis gas production. Hydrocarbon vapors may in somecircumstances be added to the steam.

[0676]FIG. 40 depicts an embodiment of in situ synthesis gas productionintegrated with a catalytic methanation process. For example, synthesisgas 1140 exiting production well 1142 may be supplied to catalyticmethanation plant 1144. In some embodiments, it may be desirable for thecomposition of produced synthesis gas, which may be used as a feed gasfor a catalytic methanation process, to have a H₂ to carbon monoxideratio of about three to one. Methane 1146 may be produced by catalyticmethanation plant 1144. Steam 1148 produced by plant 1144 may besupplied to injection well 1141 for production of synthesis gas.Examples of a catalytic methanation process are illustrated in U.S. Pat.No. 3,992,148 to Child, 4.130,575 to Jorn et al., and U.S. Pat. No.4,133,825 to Stroud et al., which are incorporated by reference as iffully set forth herein.

[0677] The synthesis gas produced may also be used as a feed for aprocess for production of methanol. Examples of processes for productionof methanol are illustrated in U.S. Pat. No. 4,407,973 to van Dijk etal., U.S. Pat. No. 4,927,857 to McShea, III et al., and U.S. Pat. No.4,994,093 to Wetzel et al., which are incorporated by reference as iffully set forth herein. The produced synthesis gas may also be used as afeed gas for a process that may convert synthesis gas to gasoline and aprocess that may convert synthesis gas to diesel fuel. Examples ofprocess for producing engine fuels are illustrated in U.S. Pat. No.4,076,761 to Chang et al., U.S. Pat. No. 4,138,442 to Chang et al., andU.S. Pat. No. 4,605,680 to Beuther et al., which are incorporated byreference as if fully set forth herein.

[0678] In one embodiment, produced synthesis gas may be used as a feedgas for production of ammonia and urea as illustrated by FIGS. 41 and42. Ammonia may be synthesized by the Haber-Bosch process, whichinvolves synthesis directly from N₂ and H₂ according to the reaction:

N₂+3H₂→2NH₃  (8)

[0679] The N₂ and H₂ may be combined, compressed to high pressure,(e.g., from about 80 bars to about 220 bars), and then heated to arelatively high temperature. The reaction mixture may be passed over acatalyst composed substantially of iron, where ammonia production mayoccur. During ammonia synthesis, the reactants (i.e., N₂ and H₂) and theproduct (i.e., ammonia) may be in equilibrium. In this manner, the totalamount of ammonia produced may be increased by shifting the equilibriumtowards product formation. Equilibrium may be shifted to productformation by removing ammonia from the reaction mixture as it isproduced.

[0680] Removal of the ammonia may be accomplished by cooling the gasmixture to a temperature between about (−5) ° C. to about 25° C. In thistemperature range, a two-phase mixture may be formed with ammonia in theliquid phase and N₂ and H₂ in the gas phase. The ammonia may beseparated from other components of the mixture. The nitrogen andhydrogen may be subsequently reheated to the operating temperature forammonia conversion and passed through the reactor again.

[0681] Urea may be prepared by introducing ammonia and carbon dioxideinto a reactor at a suitable pressure, (e.g., from about 125 barsabsolute to about 350 bars absolute), and at a suitable temperature,(e.g., from about 160° C. to about 250° C.). Ammonium carbamate may beformed according to the following reaction:

2NH₃+CO₂→NH₂(CO₂)NH₄  (9)

[0682] Urea may be subsequently formed by dehydrating the ammoniumcarbamate according to the following equilibrium reaction:

NH₂(CO₂)NH₄→NH₂(CO)NH₂+H₂O  (10)

[0683] The degree to which the ammonia conversion takes place may dependon, for example, the temperature and the amount of excess ammonia. Thesolution obtained as the reaction product may substantially includeurea, water, ammonium carbamate and unbound ammonia. The ammoniumcarbamate and the ammonia may need to be removed from the solution. Onceremoved, they may be returned to the reactor. The reactor may includeseparate zones for the formation of ammonium carbamate and urea.However, these zones may also be combined into one piece of equipment.

[0684] According to one embodiment, a high pressure urea plant mayoperate such that the decomposition of the ammonium carbamate that hasnot been converted into urea and the expulsion of the excess ammonia maybe conducted at a pressure between 15 bars absolute and 100 barsabsolute. This may be considerably lower than the pressure in the ureasynthesis reactor. The synthesis reactor may be operated at atemperature of about 180° C. to about 210° C. and at a pressure of about180 bars absolute to about 300 bars absolute. Ammonia and carbon dioxidemay be directly fed to the urea reactor. The NH₃/CO₂ molar ratio (N/Cmolar ratio) in the urea synthesis may generally be between about 3 andabout 5. The unconverted reactants may be recycled to the urea synthesisreactor following expansion, dissociation, and/or condensation.

[0685] In one embodiment, an ammonia feed stream having a selected ratioof H₂ to N₂ may be generated from a formation using enriched air. Asynthesis gas generating fluid and an enriched air stream may beprovided to the formation. The composition of the enriched air may beselected to generate synthesis gas having the selected ratio of H₂ toN₂. In one embodiment, the temperature of the formation may becontrolled to generate synthesis gas having the selected ratio.

[0686] In one embodiment, the H₂ to N₂ ratio of the feed stream providedto the ammonia synthesis process may be approximately 3:1. In otherembodiments, the ratio may range from approximately 2.8:1 to 3.2:1. Anammonia synthesis feed stream having a selected H₂ to N₂ ratio may beobtained by blending feed streams produced from different portions ofthe formation.

[0687] In one embodiment, ammonia from the ammonia synthesis process maybe provided to a urea synthesis process to generate urea. Ammoniaproduced during pyrolysis may be added to the ammonia generated from theammonia synthesis process. In another embodiment, ammonia producedduring hydrotreating may be added to the ammonia generated from theammonia synthesis process. Some of the carbon monoxide in the synthesisgas may be converted to carbon dioxide in a shift process. The carbondioxide from the shift process may be fed to the urea synthesis process.Carbon dioxide generated from treatment of the formation may also befed, in some instances, to the urea synthesis process.

[0688]FIG. 41 illustrates an embodiment of a method for production ofammonia and urea from synthesis gas using membrane-enriched air.Enriched air 1170 and steam, or water, 1172 may be fed into hot carboncontaining formation 1174 to produce synthesis gas 1176 in a wetoxidation mode as described herein.

[0689] In certain embodiments, enriched air 1170 is blended from air andoxygen streams such that the nitrogen to hydrogen ratio in the producedsynthesis gas is about 1:3. The synthesis gas may be at a correct ratioof nitrogen and hydrogen to form ammonia. For example, it has beencalculated that for a formation temperature of 700° C., a pressure of 3bar absolute. and with 13,231 tons/day of char that will be convertedinto synthesis gas, one could inject 14.7 kilotons/day of air, 6.2kilotons/day of oxygen, and 21.2 kilotons/day of steam. This wouldresult in production of 2 billion cubic feet/day of synthesis gasincluding 5689 tons/day of steam, 16,778 tons/day of carbon monoxide,1406 tons/day of hydrogen, 18,689 tons/day of carbon dioxide, 1258tons/day of methane, and 11,398 tons/day of nitrogen. After a shiftreaction (to shift the carbon monoxide to carbon dioxide, and to produceadditional hydrogen), the carbon dioxide may be removed, the productstream may be methanated (to remove residual carbon monoxide), and thenone can theoretically produce 13,840 tons/day of ammonia and 1258tons/day of methane. This calculation includes the products producedfrom Reactions (4) and (5) above.

[0690] Enriched air may be produced from a membrane separation unit.Membrane separation of air may be primarily a physical process. Basedupon specific characteristics of each molecule, such as size andpermeation rate, the molecules in air may be separated to formsubstantially pure forms of nitrogen, oxygen, or combinations thereof.

[0691] In one embodiment, a membrane system may include a hollow tubefilled with a plurality of very thin membrane fibers. Each membranefiber may be another hollow tube in which air flows. The walls of themembrane fiber may be porous and may be configured such that oxygen maypermeate through the wall at a faster rate than nitrogen. In thismanner, a nitrogen rich stream may be allowed to flow out the other endof the fiber. Air outside the fiber and in the hollow tube may be oxygenenriched. Such air may be separated for subsequent uses such asproduction of synthesis gas from a formation.

[0692] In one embodiment, the purity of the nitrogen generated may becontrolled by variation of the flow rate and/or pressure of air throughthe membrane. Increasing air pressure may increase permeation of oxygenmolecules through a fiber wall. Decreasing flow rate may increase theresidence time of oxygen in the membrane and, thus, may increasepermeation through the fiber wall. Air pressure and flow rate may beadjusted to allow a system operator to vary the amount and purity of thenitrogen generated in a relatively short amount of time.

[0693] The amount of N₂ in the enriched air may be adjusted to provide aN:H ratio of about 3:1 for ammonia production. It may be desirable togenerate synthesis gas at a temperature that may favor the production ofcarbon dioxide over carbon monoxide. It may be advantageous for thetemperature of the formation to be between about 400° C. and about 550°C. In another embodiment, it may be desirable for the temperature of theformation to be between about 400° C. and about 450° C. Synthesis gasproduced at such low temperatures may be substantially composed of N₂,H₂, and carbon dioxide with little carbon monoxide.

[0694] As illustrated in FIG. 41, a feed stream for ammonia productionmay be prepared by first feeding synthesis gas stream 1176 into ammoniafeed stream gas processing unit 1178. In ammonia feed stream gasprocessing unit 1178 the feed stream may undergo a shift reaction (toshift the carbon monoxide to carbon dioxide, and to produce additionalhydrogen). Carbon dioxide can also be removed from the feed stream, andthe feed stream can be methanated (to remove residual carbon monoxide).

[0695] In certain embodiments carbon dioxide may be separated from thefeed stream (or any gas stream) by absorption in an amine unit.Membranes or other carbon dioxide separation techniques/equipment mayalso be used to separate carbon dioxide from a feed stream.

[0696] Ammonia feed stream 1180 may be fed to ammonia productionfacility 1182 to produce ammonia 1184. Carbon dioxide 1186 exiting thegas separation unit 1178 (and/or carbon dioxide from other sources) maybe fed, with ammonia 1184, into urea production facility 1188 to produceurea 1190.

[0697] Ammonia and urea may be produced using a carbon containingformation, and using an O₂ rich stream and an N₂ rich stream. The O₂rich stream and synthesis gas generating fluid may be provided to aformation. The formation may be heated, or partially heated, byoxidation of carbon in the formation with the O₂ rich stream. H₂ in thesynthesis gas, and N₂ from the N₂ rich stream, may be provided to anammonia synthesis process to generate ammonia.

[0698]FIG. 42 illustrates a flowchart of an embodiment for production ofammonia and urea from synthesis gas using cryogenically separated air.Air 2000 may be fed into cryogenic air separation unit 2002. Cryogenicseparation involves a distillation process that may occur attemperatures between about (−168) ° C. and (−172) ° C. In otherembodiments, the distillation process may occur at temperatures betweenabout (−165) ° C. and (−175) ° C. Air may liquefy in these temperatureranges. The distillation process may be operated at a pressure betweenabout 8 bars absolute and about 10 bars absolute. High pressures may beachieved by compressing air and exchanging heat with cold air exitingthe column. Nitrogen is more volatile than oxygen and may come off as adistillate product.

[0699] N₂ 2004 exiting the separator may be utilized in heat exchanger2006 to condense higher molecular weight hydrocarbons from pyrolysisstream 2008 to remove lower molecular weight hydrocarbons from the gasphase into a liquid oil phase. Upgraded gas stream 2010 containing ahigher composition of lower molecular weight hydrocarbons than stream2008 and liquid stream 2012, which includes condensed hydrocarbons, mayexit heat exchanger 2006.

[0700] Oxygen 2014 from cryogenic separation unit 2002 and steam 2016,or water, may be fed into hot carbon containing formation 2018 toproduce synthesis gas 2020 in a continuous process as described herein.It is desirable to generate synthesis gas at a temperature that favorsthe formation of carbon dioxide over carbon monoxide. It may beadvantageous for the temperature of the formation to be between about400° C. and about 550° C. In another embodiment, it may be desirable forthe temperature of the formation to be between about 400° C. and about450° C. Synthesis gas 2020 may be substantially composed of H₂ andcarbon dioxide. Carbon dioxide may be removed from synthesis gas 2020 toprepare a feed stream for ammonia production using amine gas separationunit 2022. H₂ stream 2024 from the gas separation unit and N₂ stream2026 from the heat exchanger may be fed into ammonia production facility2028 to produce ammonia 2030. Carbon dioxide 2032 exiting the gasseparation unit and ammonia 2030 may be fed into urea productionfacility 2034 to produce urea 2036.

[0701] In one embodiment, an ammonia synthesis process feed stream maybe generated by feeding a gas containing N₂ and carbon dioxide to acarbon containing formation. The gas may be flue gas or it may be gasgenerated by an oxidation reaction of O₂ with carbon in another portionof the formation. The gas containing N₂ and carbon dioxide may beprovided to a carbon containing formation. The carbon dioxide in the gasmay adsorb in the formation and be sequestered therein. An exit streammay be produced from the formation. The exit stream may have asubstantially lower percentage of carbon dioxide than the gas enteringthe formation. The nitrogen in the exit gas may be provided to anammonia synthesis process. H₂ in synthesis gas from another portion ofthe formation may be provided to the ammonia synthesis process.

[0702]FIG. 43 illustrates an embodiment of a method for preparing anitrogen stream for an ammonia and urea process. Air 2060 may beinjected into hot carbon containing formation 2062 to produce carbondioxide by oxidation of carbon in the formation. In an embodiment, aheater may be configured to heat at least a portion of the carboncontaining formation to a temperature sufficient to support oxidation ofthe carbon. The temperature sufficient to support oxidation may be, forexample, about 260° C. for coal. Stream 2064 exiting the hot formationmay be composed substantially of carbon dioxide and nitrogen. Nitrogenmay be separated from carbon dioxide by passing the stream through coldspent carbon containing formation 2066. Carbon may be preferentiallyadsorbed versus nitrogen in the cold spent formation 2066. For example,at 50° C. and 0.35 bars, the adsorption of carbon dioxide on a spentportion of coal may be about 72 m³/metric ton compared to about 15.4m³/metric ton for nitrogen. Nitrogen 2068 exiting the cold spent portion2066 may be supplied to ammonia production facility 2070 with H₂ stream2072 to produce ammonia 2074. The H₂ stream may be obtained by methodsdisclosed herein, for example, the methods described in FIGS. 41 and 42.

[0703]FIG. 44 illustrates an embodiment of a system configured to treata relatively permeable formation. Relatively permeable formation 2200may include heavy hydrocarbons. Production wells 2210 may be disposed inrelatively permeable formation 2200. Relatively permeable formation 2200may be enclosed between substantially impermeable layers 2204. An uppersubstantially impermeable layer 2204 may be referred to as an overburdenof formation 2200. A lower substantially impermeable layer 2204 may bereferred to as a base rock of formation 2200. The overburden and thebase rock may include different types of impermeable materials. Forexample, the overburden and/or the base rock may include shale or wetcarbonate (i.e., a carbonate without hydrocarbons in it).

[0704] Low temperature heat sources 2216 and high temperature heatsources 2218 may be disposed in production well 2210. Low temperatureheat sources 2216 and high temperature heat sources 2218 may beconfigured as described herein. Production well 2210 may be configuredas described herein. Low temperature heat source 2216 may generallyrefer to a heat source, or heater, configured to provide heat to aselected mobilization section of formation 2200 substantially adjacentto the low temperature heat source. The provided heat may be configuredto heat some or all of the selected mobilization section to an averagetemperature within a mobilization temperature range of the heavyhydrocarbons contained within formation 2200. The mobilizationtemperature range may be between about 75° C. to about 150° C. Aselected mobilization temperature may be about 100° C. The mobilizationtemperature may vary, however, depending on a viscosity of the heavyhydrocarbons contained within formation 2200. For example, a highermobilization temperature may be required to mobilize a higher viscosityfluid within formation 2200.

[0705] High temperature heat source 2218 may generally refer to a heatsource, or heater, configured to provide heat to selected pyrolyzationsection 2202 of formation 2200 substantially adjacent to the heat source2218. The provided heat may be configured to heat selected pyrolyzationsection 2202 to an average temperature within a pyrolization temperaturerange of the heavy hydrocarbons contained within formation 2200. Thepyrolization temperature range may be between about 270° C. to about400° C. A selected pyrolization temperature may be about 300° C. Thepyrolization temperature may vary, however, depending on formationcharacteristics, composition, pressure, and/or a desired quality of aproduct produced from formation 2200. A quality of the product may bedetermined based upon properties of the product, (e.g., the API gravityof the product). Pyrolyzation may include cracking of the heavyhydrocarbons into hydrocarbon fragments and/or lighter hydrocarbons.Pyrolyzation of the heavy hydrocarbons tends to upgrade the quality ofthe heavy hydrocarbons.

[0706] As shown in FIG. 44, mobilized fluids in formation 2200 may flowinto selected pyrolyzation section 2202 substantially by gravity. Themobilized fluids may be upgraded by pyrolysis in selected pyrolyzationsection 2202. Flow of the mobilized fluids may optionally be increasedby providing pressurizing fluid 2214 through conduit 2212 into formation2200. Pressurizing fluid 2214 may be a fluid configured to increase apressure in formation 2200 proximate to conduit 2212. The increasedpressure proximate to conduit 2212 may increase a flow of the mobilizedfluids in formation 2200 into selected pyrolyzation section 2202. Apressure of pressurizing fluid 2214 provided by conduit 2212 may bebetween about 7 bars absolute to about 70 bars absolute. The pressure ofpressurizing fluid 2214 may vary, however, depending on, for example, aviscosity of fluid within formation 2200 and/or a desired flow rate offluid into selected pyrolyzation section 2202. Pressurizing fluid 2214may be any gas that may not substantially oxidize the heavyhydrocarbons. For example, pressurizing fluid 2214 may include N₂, CO₂,CH₄, hydrogen, steam, etc.

[0707] Production wells 2210 may be configured to remove pyrolyzationfluids and/or mobilized fluids from selected pyrolyzation section 2202.Formation fluids may be removed as a vapor. The formation fluids may befurther upgraded by high temperature heat source 2218 and lowtemperature heat source 2216 in production well 2210. Production well2210 may be further configured to control pressure in selectedpyrolyzation section 2202 to provide a pressure gradient so thatmobilized fluids flow into selected pyrolyzation section 2202 from theselected mobilization section. In some embodiments, pressure in selectedpyrolyzation section 2202 may be controlled to in turn control the flowof the mobilized fluids into selected pyrolyzation section 2202. By notheating the entire formation to pyrolyzation temperatures, the drainageprocess may produce a substantially higher ratio of energy producedversus energy input for the in situ conversion process.

[0708] In addition, pressure in relatively permeable formation 2200 maybe controlled to produce a desired quality of formation fluids. Forexample, the pressure in relatively permeable formation 2200 may beincreased to produce formation fluids with an increased API gravity ascompared to formation fluids produced at a lower pressure. Increasingthe pressure in relatively permeable formation 2200 may increase ahydrogen partial pressure in mobilized and/or pyrolyzation fluids. Theincreased hydrogen partial pressure in mobilized and/or pyrolyzationfluids may reduce heavy hydrocarbons in mobilized and/or pyrolyzationfluids. Reducing the heavy hydrocarbons may produce lighter, morevaluable hydrocarbons. An API gravity of the hydrogenated heavyhydrocarbons may be substantially higher than an API gravity of theun-hydrogenated heavy hydrocarbons.

[0709] In an embodiment, pressurizing fluid 2214 may be provided toformation 2200 through a conduit disposed in/or proximate to productionwell 2210. The conduit may be configured to provide pressurizing fluid2214 into formation 2200 proximate to upper impermeable layer 2204.

[0710] In another embodiment, low temperature heat source 2216 may beturned down and/or off in production wells 2210. The heavy hydrocarbonsin formation 2200 may be mobilized by transfer of heat from selectedpyrolyzation section 2202 into an adjacent portion of formation 2200.Heat transfer from selected pyrolyzation section 2202 may besubstantially by conduction.

[0711]FIG. 45 illustrates an embodiment configured to treat a relativelypermeable formation without substantially pyrolyzing mobilized fluids.Low temperature heat source 2216 may be disposed in production well2210. Low temperature heat source 2216, conduit 2212, and impermeablelayers 2204 may be configured as described in the embodiment shown inFIG. 44. Low temperature heat source 2216 may be further configured toprovide heat to formation 2200 to heat some or all of formation 2200 toan average temperature within the mobilization temperature range.Mobilized fluids within formation 2200 may flow towards a bottom offormation 2200 substantially by gravity. Pressurizing fluid 2214 may beprovided into formation 2200 through conduit 2212 and may be configured,as described in the embodiment shown in FIG. 44, to increase a flow ofthe mobilized fluids towards the bottom of formation 2200. Pressurizingfluid 2214 may also be provided into formation 2200 through a conduitdisposed in/or proximate to production well 2210. Formation fluids maybe removed through production well 2210 at and/or near the bottom offormation 2200. Low temperature heat source 2216 may provide heat to theformation fluids removed through production well 2210. The provided heatmay vaporize the removed formation fluids within production well 2210such that the formation fluids may be removed as a vapor. The providedheat may also increase an API gravity of the removed formation fluidswithin production well 2210.

[0712]FIG. 46 illustrates an embodiment for treating a relativelypermeable formation with layers 2201 of heavy hydrocarbons separated byimpermeable layers 2204. Heat injection well 2220 and production well2210 may be disposed in relatively permeable formation 2200.Substantially impermeable layers 2204 may separate layers 2201. Heavyhydrocarbons may be disposed in layers 2201. Low temperature heat source2216 may be disposed in injection well 2220. Low temperature heat source2216 may be configured as described in any of the above embodiments.Heavy hydrocarbons may be mobilized by heat provided from lowtemperature heat source 2216 such that a viscosity of the heavyhydrocarbons may be substantially reduced. Pressurizing fluid 2214 maybe provided through openings in injection well 2220 into layers 2201.The pressure of pressurizing fluid 2214 may cause the mobilized fluidsto flow towards production well 2210. The pressure of pressurizing fluid2214 at or near injection well 2220 may be about 7 bars absolute toabout 70 bars absolute. However, the pressure of pressurizing fluid 2214may be controlled to remain below a pressure that may lift theoverburden of relatively permeable formation 2200.

[0713] High temperature heat source 2218 may be disposed in productionwell 2210. High temperature heat source 2218 may be configured asdescribed in any of the above embodiments. Heat provided by hightemperature heat source 2218 may substantially pyrolyze a portion of themobilized fluids within a selected pyrolyzation section proximate toproduction well 2210. The pyrolyzation and/or mobilized fluids may beremoved from layers 2201 by production well 2210. High temperature heatsource 2218 may further upgrade the removed formation fluids withinproduction well 2210. The removed formation fluids may be removed as avapor through production well 2210. A pressure at or near productionwell 2210 may be less than about 70 bars absolute. By not heating theentire formation to pyrolyzation temperatures, the process may produce asubstantially higher ratio of energy produced versus energy input forthe in situ conversion process. Upgrading of the formation fluids at ornear production well 2210 may produce a substantially higher valueproduct.

[0714] In another embodiment, high temperature heat source 2218 may bereplaced with low temperature heat source 2216 within production well2210. Low temperature heat source 2216 may provide for substantiallyless pyrolyzation of the heavy hydrocarbons within layers 2201 than hightemperature heat source 2218. Therefore, the formation fluids removedthrough production well 2210 may not be as substantially upgraded asformation fluids removed through production well 2210 with hightemperature heat source 2218, as described for the embodiment shown inFIG. 46.

[0715] In another embodiment, pyrolyzation of the heavy hydrocarbons maybe increased by replacing low temperature heat source 2216 with hightemperature heat source 2218 within injection well 2220. Hightemperature heat source 2218 may provide for substantially morepyrolyzation of the heavy hydrocarbons within layers 2201 than lowtemperature heat source 2216. The formation fluids removed throughproduction well 2210 may be substantially upgraded as compared to theformation fluids removed in a process using low temperature heat source2216 within injection well 2220 as described in the embodiment shown inFIG. 46.

[0716] In some embodiments, a relatively permeable formation containingheavy hydrocarbons may be substantially below a substantially thickimpermeable layer (overburden). The overburden may have a thickness ofat least about 300 m or more. The thickness of the overburden may bedetermined by a geographical location of the relatively permeableformation.

[0717] In some embodiments, it may be more economical to provide heat tothe formation with heat sources disposed horizontally within therelatively permeable formation. A production well may also be disposedhorizontally within the relatively permeable formation. The productionwell may be disposed, however, either horizontally within the relativelypermeable formation, vertically within the relatively permeableformation, or at an angle to the relatively permeable formation.

[0718] Production well 2210 may also be further configured as describedin any of the embodiments herein. For example, production well 2210 mayinclude a valve configured to alter, maintain, and/or control a pressureof at least a portion of the formation.

[0719]FIG. 47 illustrates an embodiment for treating a relativelypermeable formation using horizontal heat sources. Heat source 2300 maybe disposed within relatively permeable formation 2200. Relativelypermeable formation 2200 may be substantially below impermeable layer2204. Impermeable layer 2204 may include, but may not be limited to,shale or carbonate. Impermeable layer 2204 may have a thickness of about20 m or more. As in FIG. 46, a thickness of impermeable layer 2204 maydepend on, for example, a geographic location of impermeable layer 2204.Heat source 2300 may be disposed horizontally within relativelypermeable formation 2200. Heat source 2300 may be configured to provideheat to a portion of relatively permeable formation 2200. Heat source2300 may include a low temperature heat source and/or a high temperatureheat source as described in any of the above embodiments. The providedheat may be configured to substantially mobilize a portion of heavyhydrocarbons within relatively permeable formation 2200 as in any of theembodiments described herein. The provided heat may also be configuredto pyrolyze a portion of heavy hydrocarbons within relatively permeableformation 2200 as in any of the embodiments described herein. A lengthof heat source 2300 disposed within relatively permeable formation 2200may be between about 50 m to about 1500 m. The length of heat source2300 within relatively permeable formation 2200 may vary, however,depending on, for example, a width of relatively permeable formation2200, a desired production rate, and an energy output of heat source2300.

[0720]FIG. 48 illustrates an embodiment for treating a relativelypermeable formation using substantially horizontal heat sources. Heatsources 2300 may be disposed horizontally within relatively permeableformation 2200. Heat sources 2300 may be configured as described in theabove embodiment shown in FIG. 47. Heat sources 2300 are depicted inFIG. 48 from a different perspective than the heat sources shown in FIG.47. Relatively permeable formation 2200 may be substantially belowimpermeable layer 2204. Production well 2302 may be disposed vertically,horizontally, or at an angle to relatively permeable formation 2200. Thelocation of production well 2302 within relatively permeable formation2200 may vary depending on, for example, a desired product and a desiredproduction rate. For example, production well 2302 may be disposedproximate to a bottom of relatively permeable formation 2200.

[0721] Heat sources 2300 may provide heat to substantially mobilize aportion of the heavy hydrocarbons within relatively permeable formation2200. The mobilized fluids may flow towards a bottom of relativelypermeable formation 2200 substantially by gravity. The mobilized fluidsmay be removed through production well 2302. Each of heat sources 2300disposed at or near the bottom of relatively permeable formation 2200may be configured to heat some or all of a section proximate the bottomof formation 2200 to a temperature sufficient to pyrolyze heavyhydrocarbons within the section. Such a section may be referred to as aselected pyrolyzation section. A temperature within the selectedpyrolyzation section may be between about 270° C. and about 400° C. andmay be configured as described in any of the embodiments herein.Pyrolysis of the heavy hydrocarbons within the selected pyrolyzationsection may convert at least a portion of the heavy hydrocarbons intopyrolyzation fluids. The pyrolyzation fluids may be removed throughproduction well 2302. Production well 2302 may be disposed within theselected pyrolyzation section. In some embodiments, one or more of heatsources 2300 may be turned down and/or off after substantiallymobilizing the majority of the heavy hydrocarbons within relativelypermeable formation 2200. Doing so may more efficiently heat theformation and/or may save on input energy costs associated with the insitu process. Also, heating during “off peak” times may be cheaper.

[0722] In an embodiment, production well 2302 may remain closed until atemperature sufficient to pyrolyze at least a portion of the heavyhydrocarbons in the selected pyrolyzation section may be reached. Doingso may inhibit production of substantial amounts of unfavorable heavyhydrocarbons from relatively permeable formation 2200. Production ofsubstantial amounts of heavy hydrocarbons may require expensiveequipment and/or reduce the life of production equipment.

[0723] In addition, heat may be provided within production well 2302 tovaporize the removed formation fluids. Heat may also be provided withinproduction well 2302 to pyrolyze and/or upgrade the removed formationfluids as described in any of the embodiments herein.

[0724] A pressurizing fluid may be provided into relatively permeableformation 2200 through heat sources 2300. The pressurizing fluid mayincrease the flow of the mobilized fluids towards production well 2302.For example, increasing the pressure of the pressurizing fluid proximateheat sources 2300 will tend to increase the flow of the mobilized fluidstowards production well 2302. The pressurizing fluid may include, butmay not be limited to, N₂, CO₂, CH₄, H₂, steam, and/or mixtures thereof.Alternatively, the pressurizing fluid may be provided through aninjection well disposed in relatively permeable formation 2200.

[0725] In addition, pressure in relatively permeable formation 2200 maybe controlled such that a production rate of formation fluids may becontrolled. The pressure in relatively permeable formation 2200 may becontrolled through, for example, production well 2302, heat sources2300, and/or a pressure control well disposed in relatively permeableformation 2200.

[0726] Production well 2302 may also be further configured as describedin any of the embodiments herein. For example, production well 2302 mayinclude a valve configured to alter, maintain, and/or control a pressureof at least a portion of the formation.

[0727] In an embodiment, an in situ process for treating a relativelypermeable formation may include providing heat to a portion of aformation from a plurality of heat sources. A plurality of heat sourcesmay be arranged within a relatively permeable formation in a pattern.FIG. 49 illustrates an embodiment of pattern 2404 of heat sources 2400and production well 2402 that may be configured to treat a relativelypermeable formation. Heat sources 2400 may be arranged in a “5 spot”pattern with production well 2402. In the “5 spot” pattern, four heatsources 2400 may be arranged substantially equidistant from productionwell 2402 and substantially equidistant from each other as depicted inFIG. 49. Depending on, for example, the heat generated by each heatsource 2400, a spacing between heat sources 2400 and production well2402 may be determined by a desired product or a desired productionrate. Heat sources 2400 may also be configured as a production well. Aspacing between heat sources 2400 and production well 2402 may be, forexample, about 15 m. Also, production well 2402 may be configured as aheat source.

[0728]FIG. 50 illustrates an alternate embodiment of pattern 2406 heatsources 2400 may be arranged in a “7 spot” pattern with production well2402. In the “7 spot” pattern, six heat sources 2400 may be arrangedsubstantially equidistant from production well 2402 and substantiallyequidistant from each other as depicted in FIG. 50. Heat sources 2400may also be configured as a production well. Also, production well 2402may be configured as a heat source. A spacing between heat sources 2400and production well 2402 may be determined as described in any of theabove embodiments.

[0729] It is to be understood a geometrical pattern of heat sources 2400and production wells 2402 is described herein by example. A pattern ofheat sources 2400 and production wells 2402 may vary depending on, forexample, the type of relatively permeable formation configured to betreated. For example, a pattern of heat sources 2400 and productionwells 2402 may include a pattern as described in any of the embodimentsherein. In addition, a location of a production well 2402 within apattern of heat sources 2400 may be determined by, for example, adesired heating rate of the relatively permeable formation, a heatingrate of the heat sources, a type of heat source, a type of relativelypermeable formation, a composition of the relatively permeableformation, a viscosity of the relatively permeable formation, and/or adesired production rate.

[0730] In some embodiments, a portion of a relatively permeableformation may be heated at a heating rate in a range from about 0.1°C./day to about 50° C./day. A majority of hydrocarbons may be producedfrom a formation at a heating rate within a range of about 0.1° C./dayto about 15° C./day. In an embodiment, the relatively permeableformation may be heated at a rate of less than about 0.7° C./day througha significant portion of a temperature range in which pyrolyzationfluids are removed from the formation. The significant portion may begreater than 50% of the time needed to span the temperature range, morethan 75% of the time needed to span the temperature range, or more than90% of the time needed to span the temperature range.

[0731] A quality of produced hydrocarbon fluids from a relativelypermeable formation may also be described by a carbon numberdistribution. In general, lower carbon number products such as productshaving carbon numbers less than about 25 may be considered to be morevaluable than products having carbon numbers greater than about 25. Inan embodiment, treating a relatively permeable formation may includeproviding heat to at least a portion of a formation to producehydrocarbon fluids from the formation of which a majority of theproduced fluid may have carbon numbers of less than approximately 25,or, for example, less than approximately 20. For example, less thanabout 20% by weight of the produced condensable fluid may have carbonnumbers greater than about 20.

[0732] In an embodiment, a pressure may be increased within a portion ofa relatively permeable formation to a desired pressure duringmobilization and/or pyrolysis of the heavy hydrocarbons. A desiredpressure may be within a range from about 2 bars absolute to about 70bars absolute. A majority of hydrocarbon fluids, however, may beproduced while maintaining the pressure within a range from about 7 barsabsolute to about 30 bars absolute. The pressure during mobilizationand/or pyrolysis may vary or be varied. The pressure may be varied tocontrol a composition of the produced fluid, to control a percentage ofcondensable fluid as compared to non-condensable fluid, or to control anAPI gravity of fluid being produced. Increasing pressure may increasethe API gravity of the produced fluid. Increasing pressure may alsoincrease a percentage of paraffins within the produced fluid.

[0733] Increasing the reservoir pressure may increase a hydrogen partialpressure within the produced fluid. For example, a hydrogen partialpressure within the produced fluid may be increased autogenously orthrough hydrogen injection. The increased hydrogen partial pressure mayupgrade the heavy hydrocarbons. The heavy hydrocarbons may be reduced tolighter, higher quality hydrocarbons. The lighter hydrocarbons may beproduced by reaction of hydrogen with heavy hydrocarbon fragments withinthe produced fluid. The hydrogen dissolved in the fluid may also reduceolefins within the produced fluid. Therefore, an increased hydrogenpressure in the fluid may decrease a percentage of olefins within theproduced fluid. Decreasing the percentage of olefins and/or heavyhydrocarbons within the produced fluid may increase a quality (e.g., anAPI gravity) of the produced fluid. In some embodiments, a pressurewithin a portion of a relatively permeable formation may be raised bygas generation within the heated portion.

[0734] In an embodiment, a fluid produced from a portion of a relativelypermeable formation by an in situ process, as described in any of theembodiments herein, may include nitrogen. For example, less than about0.5% by weight of the condensable fluid may include nitrogen or, forexample, less than about 0.1% by weight of the condensable fluid. Inaddition, a fluid produced by an in situ process as described in aboveembodiments may include oxygen. For example, less than about 7% byweight of the condensable fluid may include oxygen or, for example, lessthan about 5% by weight of the condensable fluid. A fluid produced froma relatively permeable formation may also include sulfur. For example,less than about 5% by weight of the condensable fluid may include sulfuror, for example, less than about 3% by weight of the condensable fluid.In some embodiments, a weight percent of nitrogen, oxygen, and/or sulfurin a condensable fluid may be decreased by increasing a fluid pressurein a relatively permeable formation during an in situ process.

[0735] In an embodiment, condensable hydrocarbons of a fluid producedfrom a relatively permeable formation may include aromatic compounds.For example, greater than about 20% by weight of the condensablehydrocarbons may include aromatic compounds. In another embodiment, anaromatic compound weight percent may include greater than about 30% ofthe condensable hydrocarbons. The condensable hydrocarbons may alsoinclude diaromatic compounds. For example, less than about 20% by weightof the condensable hydrocarbons may include di-aromatic compounds. Inanother embodiment, di-aromatic compounds may include less than about15% by weight of the condensable hydrocarbons. The condensablehydrocarbons may also include tri-aromatic compounds. For example, lessthan about 4% by weight of the condensable hydrocarbons may includetri-aromatic compounds. In another embodiment, tri-aromatic compoundsmay include less than about 1% by weight of the condensablehydrocarbons.

[0736] In an embodiment, an in situ process for treating heavyhydrocarbons in at least a portion of a relatively low permeabilityformation may include heating the formation from one or more heatsources. The one or more heat sources may be configured as described inany of the embodiments herein. At least one of the heat sources may bean electrical heater. In one embodiment, at least one of the heatsources may be located in a heater well. The heater well may include aconduit through which a hot fluid flows that transfers heat to theformation. At least some of the heavy hydrocarbons in a selected sectionof the formation may be pyrolyzed by the heat from the one or more heatsources. A temperature sufficient to pyrolyze heavy hydrocarbons in ahydrocarbon containing formation of relatively low permeability may bewithin a range from about 270° C. to about 300° C. In other embodiments,a temperature sufficient to pyrolyze heavy hydrocarbons may be within arange from about 300° C. to about 375° C. Pyrolyzation fluids may beproduced from the formation. In one embodiment, fluids may be producedthrough at least one production well.

[0737] In addition, heating may also increase the average permeabilityof at least a portion of the selected section. The increase intemperature of the formation may create thermal fractures in theformation. The thermal fractures may propagate between heat sources,further increasing the permeability in a portion of a selected sectionof the formation. Due to the increased permeability, mobilized fluids inthe formation may tend to flow to a heat source and may be pyrolyzed.

[0738] In one embodiment, the pressure in at least a portion of therelatively low permeability formation may be controlled to maintain acomposition of produced formation fluids within a desired range. Thecomposition of the produced formation fluids may be monitored. Thepressure may be controlled by a back pressure valve located proximate towhere the formation fluids are produced. A desired operating pressure ofa production well, such that a desired composition may be obtained, maybe determined from experimental data for the relationship betweenpressure and the composition of pyrolysis products of the heavyhydrocarbons in the formation.

[0739]FIG. 51 is a view of an embodiment of a heat source and productionwell pattern for heating heavy hydrocarbons in a relatively lowpermeability formation. Heat sources 2502, 2503, and 2504 may bearranged in a triangular pattern with the heat sources at the apices ofthe triangular grid. A production well 2500 may be located proximate tothe center of the triangular grid. In other embodiments, production well2500 may be placed at any location on the grid pattern. Heat sources maybe arranged in patterns other than the triangular pattern shown in FIG.51. For example, wells may be arranged in square patterns. Heat sources2502, 2503, and 2504 may heat the formation to a temperature at which atleast some of the heavy hydrocarbons in the formation can pyrolyze.Pyrolyzation fluids may tend to flow toward the production well, asindicated by the arrows, and formation fluids may be produced throughproduction well 2500.

[0740] In one embodiment, an average distance between heat sourceseffective to pyrolyze heavy hydrocarbons in the formation may be betweenabout 5 m and about 8 m. In one embodiment, a more effective range maybe between about 2 m and about 5 m.

[0741] One embodiment for treating heavy hydrocarbons in a portion of arelatively low permeability formation may include providing heat fromone or more heat sources to pyrolyze some of the heavy hydrocarbons andvaporize a portion of the heavy hydrocarbons in a selected section ofthe formation. Heavy hydrocarbons in the formation may be vaporized at atemperature between about 300° C. and about 350° C. In anotherembodiment, heavy hydrocarbons in the formation may be vaporized at atemperature between about 350° C. and about 450° C. The vaporized andpyrolyzed fluids may flow to a location proximate to where the fluidsare produced. In one embodiment, fluids may be produced from theformation through a production well. Due to a buildup of pressure fromvaporization, it may be necessary to relieve the pressure through theproduction well.

[0742]FIG. 51 may also represent an embodiment in which at least someheavy hydrocarbons may be pyrolyzed and a portion of the heavyhydrocarbons may be vaporized at or near at least two heat sources. Heatsources 2502, 2503, and 2504 may heat the formation to a temperaturesufficient to vaporize fluid in the formation. The vaporized fluid maytend to flow in a direction from the heat sources toward production well2500, as indicated by the arrows, where the fluid may be produced.

[0743] In one embodiment for treating heavy hydrocarbons in a portion ofa hydrocarbon containing formation of relatively low permeability, heatmay be provided from one or more heat sources with at least one of theheat sources located in a heater well. The heat sources may pyrolyze atleast some heavy hydrocarbons in a selected section of the formation andmay pressurize at least a portion of the selected section. Duringheating, the pressure within the formation may increase substantially.The pressure in the formation may be controlled such that the pressurein the formation may be maintained to produce a fluid of a desiredcomposition. Pyrolysis products may be removed from the formation asvapor from one or more heater wells disposed in the formation. Backpressure created by heating the formation may be used to produce thepyrolysis products through the one or more heater wells.

[0744]FIG. 52 is a view of an embodiment of a heat source pattern forheating heavy hydrocarbons in a portion of a hydrocarbon containingformation of relatively low permeability and producing fluids from oneor more heater wells. Heat sources 2502 may be arranged in a triangularpattern and may be disposed in heater wells. The heat sources mayprovide heat to pyrolyze some or all of the fluid in the formation.Fluids may be produced through one or more of the heater wells.

[0745] One embodiment for treating heavy hydrocarbons in a portion of ahydrocarbon containing formation of relatively low permeability mayinclude heating the formation to create at least two zones within theformation such that the at least two zones have different averagetemperatures. One or more heat sources may heat a selected first sectionof the formation that creates a pyrolysis zone in which heavyhydrocarbons may be pyrolyzed within the selected first section. Inaddition, one or more heat sources may heat a selected second section ofthe formation such that at least some of the heavy hydrocarbons in thesecond selected section have an average temperature less than theaverage temperature of the pyrolysis zone.

[0746] Heating the selected second section may decrease the viscosity ofsome of the heavy hydrocarbon in the selected second section to create alow viscosity zone. The decrease in viscosity of the heavy hydrocarbonsin the selected second section may be sufficient to produce mobilizedfluids within the selected second section. The mobilized fluids may flowinto the pyrolysis zone. For example, increasing the temperature of theheavy hydrocarbons in the formation to between about 200° C. and about250° C. may decrease the viscosity of the heavy hydrocarbonssufficiently for the heavy hydrocarbons to flow through the formation.In another embodiment, increasing the temperature of the fluid tobetween about 180° C. and about 200° C. may also be sufficient tomobilize the heavy hydrocarbons. For example, the viscosity of heavyhydrocarbons in a formation at 200° C. may be about 50 centipoise toabout 200 centipoise.

[0747] Heating may create thermal fractures that may propagate betweenheat sources in both the selected first section and the selected secondsection. The thermal fractures may substantially increase thepermeability of the formation and may facilitate the flow of mobilizedfluids from the low viscosity zone to the pyrolysis zone. In oneembodiment, a vertical hydraulic fracture may be created in theformation to further increase permeability. The presence of a hydraulicfracture may also be desirable since heavy hydrocarbons that may collectin the hydraulic fracture may have an increased residence time in thepyrolysis zone. The increased residence time may result in increasedpyrolysis of the heavy hydrocarbons in the pyrolysis zone.

[0748] Also, substantially simultaneously with the decrease inviscosity, the pressure in the low viscosity zone may increase due tothermal expansion of the formation and evaporation of entrained water inthe formation to form steam. For example, pressures in the low viscosityzone may range from about 10 bars absolute to an overburden pressure,which may be about 70 bars absolute. In other embodiments the pressuremay range from about 15 bars absolute to about 50 bars absolute. Thevalue of the pressure may depend upon factors such as, but not limitedto, the degree of thermal fracturing, the amount of water in theformation, and material properties of the formation. The pressure in thepyrolysis zone may be substantially lower than the pressure in the lowviscosity zone because of the higher permeability of the pyrolysis zone.The higher temperature in the pyrolysis zone compared to the lowviscosity zone may cause a higher degree of thermal fracturing, and thusa greater permeability. For example, pyrolysis zone pressures may rangefrom about 3.5 bars absolute to about 10 bars absolute. In otherembodiments, pyrolysis zone pressures may range from about 10 barsabsolute to about 15 bars absolute.

[0749] The pressure differential between the pyrolysis zone and the lowviscosity zone may force some mobilized fluids to flow from the lowviscosity zone into the pyrolysis zone. Heavy hydrocarbons in thepyrolysis zone may be upgraded by pyrolysis into pyrolyzation fluids.Pyrolyzation fluids may be produced from the formation through aproduction well. In another embodiment, a pyrolyzation fluid producedfrom the formation may include a liquid.

[0750] In one embodiment, the density of the heat sources in thepyrolysis zone may be greater than the density of heat sources in thelow viscosity zone. The increased density of heat sources in thepyrolysis zone may establish and maintain a uniform pyrolysistemperature in the pyrolysis zone. Using a lower density of heat sourcesin the low viscosity zone may be more efficient and economical due tothe lower temperature required in the low viscosity zone. In oneembodiment, an average distance between heat sources for heating thefirst selected section may be between about 5 m and about 10 m.Alternatively, an average distance may be between about 2 m and about 5m. In some embodiments, an average distance between heat sources forheating the second selected section may be between about 5 m and about20 m.

[0751] In an embodiment, the pyrolysis zone and one or more lowviscosity zones may be heated sequentially over time. Heat sources mayheat the first selected section until an average temperature of thepyrolysis zone reaches a desired pyrolysis temperature. Subsequently,heat sources may heat one or more low viscosity zones of the selectedsecond section that may be nearest the pyrolysis zone until such lowviscosity zones reach a desired average temperature. Heating lowviscosity zones of the selected second section farther away from thepyrolysis zone may continue in a like manner.

[0752] In one embodiment, heat may be provided to a formation to createa planar pyrolysis zone and a planar low viscosity zone. One or moreplanar low viscosity zones may be created with symmetry about thepyrolysis zone and may tend to force heavy hydrocarbons toward thepyrolysis zone. In one embodiment, fluids in the pyrolysis zone may beproduced from a production well located in the pyrolysis zone.

[0753]FIG. 53 is a view an embodiment of a heat source and productionwell pattern illustrating a pyrolysis zone and a low viscosity zone.Heat sources 2512 along plane 2504 and plane 2506 may heat planar region2508 to create a pyrolysis zone. Heating may create thermal fractures2510 in the pyrolysis zone. Heating with heat sources 2514 in planes2516, 2518, 2520, and 2522 may create a low viscosity zone with anincreased permeability due to thermal fractures. Pressure differentialbetween the low viscosity zone and the pyrolysis zone may forcemobilized fluid from the low viscosity zone into the pyrolysis zone. Thepermeability created by thermal fractures 2510 may be sufficiently highto create a substantially uniform pyrolysis zone. Pyrolyzation fluidsmay be produced through production well 2500.

[0754] In one embodiment, it may be desirable to create the pyrolysiszone and low viscosity zone sequentially over time. The heat sourcesnearest the pyrolysis zone may be activated first, for example, heatsources 2512 in plane 2504 and plane 2506 of FIG. 53. A substantiallyuniform temperature may be established in the pyrolysis zone after aperiod of time. Mobilized fluids that flow through the pyrolysis zonemay undergo pyrolysis and vaporize. Once the pyrolysis zone isestablished, heat sources in the low viscosity zone (e.g., heat sources2514 in plane 2516 and plane 2520) nearest the pyrolysis zone may beturned on and/or up to establish a low viscosity zone. A larger lowviscosity zone may be developed by repeatedly activating heat sources(e.g., heat sources 2514 in plane 2518 and plane 2522) farther away fromthe pyrolysis zone.

[0755]FIG. 54 is an expanded view of the pattern shown in FIG. 53. Thefour planar vertical regions 2540 that correspond to region 2508 in FIG.53, may include heat sources that may create pyrolysis zones. Regions2548, 2550, and 2552 may include heat sources that apply heat to createa low viscosity zone. Production wells 2500 may be disposed in regionswhere pyrolysis occurs and may be configured to remove the pyrolyzationfluids. In one embodiment, a length of the pyrolysis zones 2540 may bebetween about 75 m and about 100 m. In another embodiment, a length ofthe pyrolysis zones may be between about 100 m and about 125 m. Inanother embodiment, an average distance between production wells in thesame plane may be between about 100 m and about 150 m. In oneembodiment, a distance between plane 2542 and plane 2544 may be betweenabout 40 m and about 80 m. In some embodiments, more than one productionwell may be disposed in a region where pyrolysis occurs. Plane 2542 andplane 2544 may be substantially parallel. The formation may includeadditional planar vertical pyrolysis zones that may be substantiallyparallel to each other. Hot fluids may be provided into vertical planarregions such that in situ pyrolysis of heavy hydrocarbons may occur.Pyrolyzation fluids may be removed by production wells disposed in thevertical planar regions.

[0756] An embodiment of a planar pyrolysis zone may include a verticalhydraulic fracture created by a production well in the formation. Theformation may include heat sources located substantially parallel to thevertical hydraulic fracture in the formation. Heat sources in a planarregion adjacent to the fracture may provide heat sufficient to pyrolyzeat least some or all of the heavy hydrocarbons in a pyrolysis zone. Heatsources outside the planar region may heat the formation to atemperature sufficient to decrease the viscosity of the fluids in a lowviscosity zone.

[0757]FIG. 55 is a view of an embodiment for treating heavy hydrocarbonsin at least a portion of a hydrocarbon containing formation ofrelatively low permeability that may include a well pattern and avertical hydraulic fracture. Production well 2600 may be configured tocreate fracture 2602 by methods described in any of the embodimentsherein. The width of fracture 2602 generated by hydraulic fracturing maybe between about 0.3 cm and about 1 cm. In other embodiments, the widthof fracture 2602 may be between about 1 cm and about 3 cm. The pyrolysiszone may be formed in a planar region on either side of the verticalhydraulic fracture by heating the planar region to an averagetemperature within a pyrolysis temperature range with heat sources 2604in plane 2605 and plane 2606. Creation of a low viscosity zone on bothsides of the pyrolysis zone, above plane 2605 and below plane 2606, maybe accomplished by heat sources outside the pyrolysis zone. For example,heat sources 2608 in planes 2610, 2612, 2614, and 2616 may heat the lowviscosity zone to a temperature sufficient to lower the viscosity ofheavy hydrocarbons in the formation. Mobilized fluids in the lowviscosity zone may flow to the pyrolysis zone due to the pressuredifferential between the low viscosity zone and the pyrolysis zone andthe increased permeability from thermal fractures.

[0758]FIG. 56 is an expanded view of an embodiment shown in FIG. 55.FIG. 56 illustrates a formation with two fractures 2645 a and 2645 balong plane 2645 and two fractures 2646 a and 2646 b along plane 2646.Each fracture may be produced using production wells 2640. Plane 2645and plane 2646 may be substantially parallel. The length of a fracturecreated by hydraulic fracturing in relatively low permeabilityformations may be between about 75 m and about 100 m. In someembodiments, the vertical hydraulic fracture may be between about 100 mand about 125 m. Vertical hydraulic fractures may propagatesubstantially equal distances along a plane from a production well.Therefore, since it may be undesirable for fractures along the sameplane to join, the distance between production wells along the sameplane may be between about 100 m and about 150 m. As the distancebetween fractures on different planes increases, for example thedistance between plane 2645 and plane 2646, the flow of mobilized fluidsfarthest from either fracture may decrease. A distance between fractureson different planes that may be economical and effective for thetransport of mobilized fluids to the pyrolysis zone may be about 40 m toabout 80 m.

[0759] Plane 2648 and plane 2649 may include heat sources that mayprovide heat sufficient to create a pyrolysis zone between plane 2648and plane 2649. Plane 2651 and plane 2652 may include heat sources thatcreate a pyrolysis zone between plane 2651 and plane 2652. Heat sourcesin regions 2650, 2660, 2655, and 2656 may provide heat that may createlow viscosity zones. Mobilized fluids in regions 2650, 2660, 2655, and2656 may tend to flow in a direction toward the closest fracture in theformation. Mobilized fluids entering the pyrolysis zone may bepyrolyzed. Pyrolyzation fluids may be produced from production wells2640.

[0760] In one embodiment, heat may be provided to a relatively lowpermeability formation to create a radial pyrolysis zone and a lowviscosity zone. A radial heating region may be created that tends toforce fluids toward a pyrolysis zone. Fluids may be pyrolyzed in thepyrolysis zone Pyrolyzation fluids may be produced from production wellsdisposed in the pyrolysis zone. Heat sources may be located around aproduction well in concentric rings such as regular polygons. A varietyof configurations of heat sources may be possible. Heat sources in aring nearest the production well may heat the fluid to a pyrolysistemperature to create a radial pyrolysis zone. Additional concentricrings of heat sources may radiate outward from the pyrolysis zone andmay heat the fluid to create a low viscosity zone. Mobilized fluid inthe low viscosity zone may flow to the pyrolysis zone due to thepressure differential between the low viscosity zone and the pyrolysiszone, and from the increased permeability due to thermal fracturing.Pyrolyzation fluids may be produced from the formation through theproduction well.

[0761] Several patterns of heat sources arranged in rings aroundproduction wells may be utilized to create a radial pyrolysis region inhydrocarbon containing formations. Various patterns shown in FIGS. 57-70are described herein. Although such patterns are discussed in thecontext of heavy hydrocarbons, it is to be understood that any of thepatterns shown in FIGS. 57-70 may be used for other hydrocarboncontaining formations (e.g., for coal, oil shale, etc.).

[0762]FIG. 57 illustrates an embodiment of a pattern of heat sources2705 that may create a radial pyrolysis zone surrounded by a lowviscosity zone. Production well 2701 may be surrounded by concentricrings 2702, 2703, and 2704 of heat sources 2705. Heat sources 2705 inring 2702 may heat the formation to create radial pyrolysis zone 2710.Heat sources 2705 in rings 2703 and 2704 outside pyrolysis zone 2710 mayheat the formation to create a low viscosity zone. Mobilized fluids mayflow radially inward from the low viscosity zone to the pyrolysis zone2710. Fluids may be produced through production well 2701. In oneembodiment, an average distance between heat sources may be betweenabout 2 m and about 10 m. Alternatively, the average distance may bebetween about 10 m and about 20 m.

[0763] As in other embodiments, it may be desirable to create pyrolysiszones and low viscosity zones sequentially. Heat sources 2705 nearestproduction well 2701 may be activated first, for example, heat sources2705 in ring 2702. A substantially uniform temperature pyrolysis zonemay be established after a period of time. Fluids that flow through thepyrolysis zone may undergo pyrolysis and vaporization. Once thepyrolysis zone is established, heat sources 2705 in the low viscosityzone substantially near the pyrolysis zone (e.g., heat sources 2705 inring 2703) may be activated to provide heat to a portion of a lowviscosity zone. Fluid may flow inward towards production well 2701 dueto a pressure differential between the low viscosity zone and thepyrolysis zone, as indicated by the arrows. A larger low viscosity zonemay be developed by repeatedly activating heat sources farther away fromthe fracture, for example, heat sources 2705 in ring 2704.

[0764] Several patterns of heat sources and production wells may beutilized in embodiments of radial heating zones for treating arelatively low permeability formation. The heat sources may be arrangedin rings around the production wells. The pattern around each productionwell may be a hexagon that may contain a number of heat sources.

[0765] In FIG. 58, production well 2701 and heat source 2712 may belocated at the apices of a triangular grid. The triangular grid may bean equilateral triangular grid with sides of length, s. Production wells2701 may be spaced at a distance of about 1.732(s). Production well 2701may be disposed at a center of a hexagonal pattern with one ring 2713 ofsix heat sources 2712. Each heat source 2712 may provide substantiallyequal amounts of heat to three production wells. Therefore, each ring2713 of six heat sources 2712 may contribute approximately twoequivalent heat sources per production well 2701.

[0766]FIG. 59 illustrates a pattern of production wells 2701 with aninner hexagonal ring 2713 and an outer hexagonal ring 2715 of heatsources 2712. In this pattern, production wells 2701 may be spaced at adistance of about 2(1.732)s. Heat sources 2712 may be located at allother grid positions. This pattern may result in a ratio of equivalentheat sources to production wells that may approach eleven.

[0767]FIG. 60 illustrates three rings of heat sources 2712 surroundingproduction well 2701. Production well 2701 may be surrounded by ring2713 of six heat sources 2712. Second hexagonally shaped ring 2716 oftwelve heat sources 2712 may surround ring 2713. Third ring 2718 of heatsources 2712 may include twelve heat sources that may providesubstantially equal amounts of heat to two production wells and six heatsources that may provide substantially equal amounts of heat to threeproduction wells. Therefore, a total of eight equivalent heat sourcesmay be disposed on third ring 2718. Production well 2701 may be providedheat from an equivalent of about twenty-six heat sources. FIG. 61illustrates an even larger pattern that may have a greater spacingbetween production wells 2701.

[0768] Alternatively, square patterns may be provided with productionwells placed, for example, in the center of each third square, resultingin four heat sources for each production well. Production wells may beplaced within each fifth square in a square pattern, which may result insixteen heat sources for each production well.

[0769]FIGS. 62, 63, 64, and 65 illustrate alternate embodiments in whichboth production wells and heat sources may be located at the apices of atriangular grid. In FIG. 62, a triangular grid, with a spacing of s, mayhave production wells 2701 spaced at a distance of 2s. A hexagonalpattern may include one ring 2730 of six heat sources 2732. Each heatsource 2732 may provide substantially equal amounts of heat to twoproduction wells 2701. Therefore, each ring 2730 of six heat sources2732 contributes approximately three equivalent heat sources perproduction well 2701.

[0770]FIG. 63 illustrates a pattern of production wells 2701 with innerhexagonal ring 2734 and outer hexagonal ring 2736. Production wells 2701may be spaced at a distance of 3s. Heat sources 2732 may be located atapices of hexagonal ring 2734 and hexagonal ring 2736. Hexagonal ring2734 and hexagonal ring 2736 may include six heat sources each. Thepattern in FIG. 63 may result in a ratio of heat sources 2732 toproduction well 2701 of eight.

[0771]FIG. 64 illustrates a pattern of production wells 2701 also withtwo hexagonal rings of heat sources surrounding each production well.Production well 2701 may be surrounded by ring 2738 of six heat sources2732. Production wells 2701 may be spaced at a distance of 4s. Secondhexagonally shaped ring 2740 may surround ring 2738. Second hexagonallyshaped ring 2740 may include twelve heat sources 2732. This pattern mayresult in a ratio of heat sources 2732 to production wells 2701 that mayapproach fifteen.

[0772]FIG. 65 illustrates a pattern of heat sources 2732 with threerings of heat sources 2732 surrounding each production well 2701.Production wells 2701 may be surrounded by ring 2742 of six heat sources2732. Second ring 2744 of twelve heat sources 2732 may surround ring2742. Third ring 2746 of heat sources 2732 may surround second ring2744. Third ring 2746 may include 6 equivalent heat sources. Thispattern may result in a ratio of heat sources 2732 to production wells2701 that is about 24:1.

[0773]FIGS. 66, 67, 68, and 69 illustrate patterns in which theproduction well may be disposed at a center of a triangular grid suchthat the production well may be equidistant from the apices of thetriangular grid. In FIG. 66, the triangular grid of heater wells with aspacing of s may include production wells 2760 spaced at a distance ofs. Each production well 2760 may be surrounded by ring 2764 of threeheat sources 2762. Each heat source 2762 may provide substantially equalamounts of heat to three production wells 2760: Therefore, each ring2764 of three heat sources 2762 may contribute one equivalent heatsource per production well 2760.

[0774]FIG. 67 illustrates a pattern of production wells 2760 with innertriangular ring 2766 and outer ring 2768. In this pattern, productionwells 2760 may be spaced at a distance of 2s. Heat sources 2762 may belocated at apices of inner ring 2766 and outer ring 2768. Inner ring maycontribute three equivalent heat sources per production well 2760. Outerhexagonal ring 2768 containing three heater wells may contribute oneequivalent heat source per production well 2760. Thus, a total of fourequivalent heat sources may provide heat to production well 2760.

[0775]FIG. 68 illustrates a pattern of production wells with one innertriangular ring of heat sources surrounding each production well, oneinverted triangular ring, and one irregular hexagonal outer ring.Production wells 2760 may be surrounded by ring 2770 of three heatsources 2762. Production wells 2760 may be spaced at a distance of 3s.Irregular hexagonally shaped ring 2772 of nine heat sources 2762 maysurround ring 2770. This pattern may result in a ratio of heat sources2762 to production wells 2760 of three.

[0776]FIG. 69 illustrates triangular patterns of heat sources with threerings of heat sources surrounding each production well. Production wells2760 may be surrounded by ring 2774 of three heat sources 2762.Irregular hexagon pattern 2776 of nine heat sources 2762 may surroundring 2774. Third set 2778 of heat sources 2762 may surround hexagonalpattern 2776. Third set 2778 may contribute four equivalent heat sourcesto production well 2760. A ratio of equivalent heat sources toproduction well 2760 may be sixteen.

[0777] One embodiment for treating heavy hydrocarbons in at least aportion of a relatively low permeability formation may include heatingthe formation from three or more heat sources. At least three of theheat sources may be arranged in a substantially triangular pattern. Atleast some of the heavy hydrocarbons in a selected section of theformation may be pyrolyzed by the heat from the three or more heatsources. Pyrolyzation fluids generated by pyrolysis of heavyhydrocarbons in the formation may be produced from the formation. In oneembodiment, fluids may be produced through at least one production welldisposed in the formation.

[0778]FIG. 70 depicts an embodiment of a pattern of heat sources 2705arranged in a triangular pattern. Production well 2701 may be surroundedby triangles 2780, 2782, and 2784 of heat sources 2705. Heat sources2705 in triangles 2780, 2782, and 2784 may provide heat to theformation. The provided heat may raise an average temperature of theformation to a pyrolysis temperature. Pyrolyzation fluids may flow toproduction well 2701. Formation fluids may be produced in productionwell 2701.

[0779]FIG. 71 illustrates a schematic diagram of an embodiment ofsurface facilities 2800 that may be configured to treat a formationfluid. The formation fluid may be produced though a production well asdescribed herein. The formation fluid may include any of a formationfluid produced by any of the methods as described herein. As shown inFIG. 71, surface facilities 2800 may be coupled to well head 2802. Wellhead 2802 may also be coupled to a production well formed in aformation. For example, the well head may be coupled to a productionwell by various mechanical devices proximate an upper surface of theformation. Therefore, a formation fluid produced through a productionwell may also flow through well head 2802. Well head 2802 may beconfigured to separate the formation fluid into gas stream 2804, liquidhydrocarbon condensate stream 2806, and water stream 2808.

[0780] Surface facilities 2800 may be configured such that water stream2808 may flow from well head 2802 to a portion of a formation, to acontainment system, or to a processing unit. For example, water stream2808 may flow from well head 2802 to an ammonia production unit. Thesurface facilities may be configured such that ammonia produced in theammonia production unit may flow to an ammonium sulfate unit. Theammonium sulfate unit may be configured to combine the ammonia withH₂SO₄ or SO₂/SO₃ to produce ammonium sulfate. In addition, the surfacefacilities may be configured such that ammonia produced in the ammoniaproduction unit may flow to a urea production unit. The urea productionunit may be configured to combine carbon dioxide with the ammonia toproduce urea.

[0781] Surface facilities 2800 may be configured such that gas stream2804 may flow through a conduit from well head 2802 to gas treatmentunit 2810. The conduit may include a pipe or any other fluidcommunication mechanism known in the art. The gas treatment unit may beconfigured to separate various components of gas stream 2804. Forexample, the gas treatment unit may be configured to separate gas stream2804 into carbon dioxide stream 2812, hydrogen sulfide stream 2814,hydrogen stream 2816, and stream 2818 that may include, but may not belimited to, methane, ethane, propane, butanes (including n-butane oriso-butane), pentane, ethene, propene, butene, pentene, water orcombinations thereof.

[0782] Surface facilities 2800 may be configured such that the carbondioxide stream may flow through a conduit to a formation, to acontainment system, to a disposal unit, and/or to another processingunit. In addition, the facilities may be configured such that thehydrogen sulfide stream may also flow through a conduit to a containmentsystem and/or to another processing unit. For example, the hydrogensulfide stream may be converted into elemental sulfur in a Claus processunit. The gas treatment unit may also be configured to separate gasstream 2804 into stream 2819 that may include heavier hydrocarboncomponents from gas stream 2804. Heavier hydrocarbon components mayinclude, for example, hydrocarbons having a carbon number of greaterthan about 5. Surface facilities 2800 may be configured such thatheavier hydrocarbon components in stream 2819 may be provided to liquidhydrocarbon condensate stream 2806.

[0783] Surface facilities 2800 may also include processing unit 2821.Processing unit 2821 may be configured to separate stream 2818 into anumber of streams. Each of the number of streams may be rich in apredetermined component or a predetermined number of compounds. Forexample, processing unit 2821 may separate stream 2818 into firstportion 2820 of stream 2818, second portion 2823 of stream 2818, thirdportion 2825 of stream 2818, and fourth portion 2831 of stream 2818.First portion 2820 of stream 2818 may include lighter hydrocarboncomponents such as methane and ethane. The surface facilities may beconfigured such that first portion 2820 of stream 2818 may flow from gastreatment unit 2810 to power generation unit 2822.

[0784] Power generation unit 2822 may be configured for extractinguseable energy from the first portion of stream 2818. For example,stream 2818 may be produced under pressure. In this manner, powergeneration unit may include a turbine configured to generate electricityfrom the first portion of stream 2818. The power generation unit mayalso include, for example, a molten carbonate fuel cell, a solid oxidefuel cell, or other type of fuel cell. The facilities may be furtherconfigured such that the extracted useable energy may be provided touser 2824. User 2824 may include, for example, surface facilities 2800,a heat source disposed within a formation, and/or a consumer of useableenergy.

[0785] Second portion 2823 of stream 2818 may also include lighthydrocarbon components. For example, second portion 2823 of stream 2818may include, but may not be limited to, methane and ethane. Surfacefacilities 2800 may also be configured such that second portion 2823 ofstream 2818 may be provided to natural gas grid 2827. Alternatively,surface facilities may also be configured such that second portion 2823of stream 2818 may be provided to a local market. The local market mayinclude a consumer market or a commercial market. In this manner, thesecond portion 2823 of stream 2818 may be used as an end product or anintermediate product depending on, for example, a composition of thelight hydrocarbon components.

[0786] Third portion 2825 of stream 2818 may include liquefied petroleumgas (“LPG”). Major constituents of LPG may include hydrocarboncontaining three or four carbon atoms such as propane and butane. Butanemay include n-butane or iso-butane. LPG may also include relativelysmall concentrations of other hydrocarbons such as ethene, propene,butene, and pentene. Depending on the source of LPG and how it has beenproduced, however, LPG may also include additional components. LPG maybe a gas at atmospheric pressure and normal ambient temperatures. LPGmay be liquefied, however, when moderate pressure is applied or when thetemperature is sufficiently reduced. When such moderate pressure isreleased, LPG gas may have about 250 times a volume of LPG liquid.Therefore, large amounts of energy may be stored and transportedcompactly as LPG.

[0787] Surface facilities 2800 may also be configured such that thirdportion 2825 of stream 2818 may be provided to local market 2829. Thelocal market may include a consumer market or a commercial market. Inthis manner, the third portion 2825 of stream 2818 may be used as an endproduct or an intermediate product depending on, for example, acomposition of the LPG. For example, LPG may be used in applications,such as food processing, aerosol propellants, and automotive fuel. LPGmay usually be available in one or two forms for standard heating andcooking purposes: commercial propane and commercial butane. Propane maybe more versatile for general use than butane because, for example,propane has a lower boiling point than butane.

[0788] Surface facilities 2800 may also be configured such that fourthportion 2831 of stream 2818 may flow from the gas treatment unit tohydrogen manufacturing unit 2828. Hydrogen containing stream 2830 isshown exiting hydrogen manufacturing unit 2828. Examples of hydrogenmanufacturing unit 2828 may include a steam reformer and a catalyticflameless distributed combustor with a hydrogen separation membrane.FIG. 72 illustrates an embodiment of a catalytic flameless distributedcombustor. An example of a catalytic flameless distributed combustorwith a hydrogen separation membrane is illustrated in U.S. patentapplication Ser. No. 60/273,354, filed on Mar. 5, 2001, which isincorporated by reference as if fully set forth herein. A catalyticflameless distributed combustor may include fuel line 2850, oxidant line2852, catalyst 2854, and membrane 2856. Fourth portion 2831 of stream2818 may be provided to hydrogen manufacturing unit 2828 as fuel 2858.Fuel 2858 within fuel line 2850 may mix within reaction zone in annularspace 2859 between the fuel line and the oxidant line. Reaction of thefuel with the oxidant in the presence of catalyst 2854 may producereaction products that include H₂. Membrane 2856 may allow a portion ofthe generated H₂ to pass into annular space 2860 between outer wall 2862of oxidant line 2852 and membrane 2856. Excess fuel passing out of fuelline 2850 may be circulated back to entrance of hydrogen manufacturingunit 2828. Combustion products leaving oxidant line 2852 may includecarbon dioxide and other reactions products as well as some fuel andoxidant. The fuel and oxidant may be separated and recirculated back tothe hydrogen manufacturing unit. Carbon dioxide may be separated fromthe exit stream. The carbon dioxide may be sequestered within a portionof a formation or used for an alternate purpose.

[0789] Fuel line 2850 may be concentrically positioned within oxidantline 2852. Critical flow orifices within fuel line 2850 may beconfigured to allow fuel to enter into a reaction zone in annular space2859 between the fuel line and oxidant line 2852. The fuel line maycarry a mixture of water and vaporized hydrocarbons such as, but notlimited to, methane, ethane, propane, butane, methanol, ethanol, orcombinations thereof. The oxidant line may carry an oxidant such as, butnot limited to, air, oxygen enriched air, oxygen, hydrogen peroxide, orcombinations thereof.

[0790] Catalyst 2854 may be located in the reaction zone to allowreactions that produce H₂ to proceed at relatively low temperatures.Without a catalyst and without membrane separation of H₂, a steamreformation reaction may need to be conducted in a series of reactorswith temperatures for a shift reaction occurring in excess of 980° C.With a catalyst and with separation of H₂ from the reaction stream, thereaction may occur at temperatures within a range from about 300° C. toabout 600° C., or within a range from about 400° C. to about 500° C.Catalyst 2854 may be any steam reforming catalyst. In selectedembodiments, catalyst 2854 is a group VIII transition metal, such asnickel. The catalyst may be supported on porous substrate 2864. Thesubstrate may include group III or group IV elements, such as, but notlimited to, aluminum, silicon, titanium, or zirconium. In an embodiment,the substrate is alumina (Al₂O₃).

[0791] Membrane 2856 may remove H₂ from a reaction stream within areaction zone of a hydrogen manufacturing unit 2828. When H₂ is removedfrom the reaction stream, reactions within the reaction zone maygenerate additional H₂. A vacuum may draw H₂ from an annular regionbetween membrane 2856 and wall 2862 of oxidant line 2852. Alternately,H₂ may be removed from the annular region in a carrier gas. Membrane2856 may separate H₂ from other components within the reaction stream.The other components may include, but are not limited to, reactionproducts, fuel, water, and hydrogen sulfide. The membrane may be ahydrogen-permeable and hydrogen selective material such as, but notlimited to, a ceramic, carbon, metal, or combination thereof. Themembrane may include, but is not limited to, metals of group VIII, V,III, or I such as palladium, platinum, nickel, silver, tantalum,vanadium, yttrium, and/or niobium. The membrane may be supported on aporous substrate such as alumina. The support may separate the membrane2856 from catalyst 2854. The separation distance and insulationproperties of the support may help to maintain the membrane within adesired temperature range. In this manner, hydrogen manufacturing unit2828 may be configured to produce hydrogen-rich stream 2830 from thesecond portion stream 2818. The surface facilities may also beconfigured such that hydrogen-rich stream 2830 may flow into hydrogenstream 2816 to form stream 2832. In this manner, stream 2832 may includea larger volume of hydrogen than either hydrogen-rich stream 2830 orhydrogen stream 2816.

[0792] Surface facilities 2800 may be configured such that hydrocarboncondensate stream 2806 may flow through a conduit from well head 2802 tohydrotreating unit 2834. Hydrotreating unit 2834 may be configured tohydrogenate hydrocarbon condensate stream 2806 to form hydrogenatedhydrocarbon condensate stream 2836. The hydrotreater may be configuredto upgrade and swell the hydrocarbon condensate. For example, surfacefacilities 2800 may also be configured to provide stream 2832 (whichincludes a relatively high concentration of hydrogen) to hydrotreatingunit 2834. In this manner, H₂ in stream 2832 may hydrogenate a doublebond of the hydrocarbon condensate, thereby reducing a potential forpolymerization of the hydrocarbon condensate. In addition, hydrogen mayalso neutralize radicals in the hydrocarbon condensate. In this manner,the hydrogenated hydrocarbon condensate may include relatively shortchain hydrocarbon fluids. Furthermore, hydrotreating unit 2834 may beconfigured to reduce sulfur, nitrogen, and aromatic hydrocarbons inhydrocarbon condensate stream 2806. Hydrotreating unit 2834 may be adeep hydrotreating unit or a mild hydrotreating unit. An appropriatehydrotreating unit may vary depending on, for example, a composition ofstream 2832, a composition of the hydrocarbon condensate stream, and/ora selected composition of the hydrogenated hydrocarbon condensatestream.

[0793] Surface facilities 2800 may be configured such that hydrogenatedhydrocarbon condensate stream 2836 may flow from hydrotreating unit 2834to transportation unit 2838. Transportation unit 2838 may be configuredto collect a volume of the hydrogenated hydrocarbon condensate and/or totransport the hydrogenated hydrocarbon condensate to market center 2840.For example, market center 2840 may include, but may not be limited to,a consumer marketplace or a commercial marketplace. A commercialmarketplace may include, but may not be limited to, a refinery. In thismanner, the hydrogenated hydrocarbon condensate may be used as an endproduct or an intermediate product depending on, for example, acomposition of the hydrogenated hydrocarbon condensate.

[0794] Alternatively, surface facilities 2800 may be configured suchthat hydrogenated hydrocarbon condensate stream 2836 may flow to asplitter or an ethene production unit. The splitter may be configured toseparate the hydrogenated hydrocarbon condensate stream into ahydrocarbon stream including components having carbon numbers of 5 or 6,a naphtha stream, a kerosene stream, and a diesel stream. Streamsexiting the splitter may be fed to the ethene production unit. Inaddition, the hydrocarbon condensate stream and the hydrogenatedhydrocarbon condensate stream may be fed to the ethene production unit.Ethene produced by the ethene production unit may be fed to apetrochemical complex to produce base and industrial chemicals andpolymers. Alternatively, the streams exiting the splitter may be fed toa hydrogen conversion unit. A recycle stream may be configured to flowfrom the hydrogen conversion unit to the splitter. The hydrocarbonstream exiting the splitter and the naphtha stream may be fed to a mogasproduction unit. The kerosene stream and the diesel stream may bedistributed as product.

[0795]FIG. 73 illustrates an embodiment of an additional processing unitthat may be included in surface facilities such as the facilitiesdepicted in FIG. 71. Air separation unit 2900 may be configured togenerate nitrogen stream 2902 and oxygen stream 2905. Oxygen stream 2905and steam 2904 may be injected into exhausted coal resource 2906 togenerate synthesis gas 2907. Produced synthesis gas 2907 may be providedto Shell Middle Distillates process unit 2910 that may be configured toproduce middle distillates 2912. In addition, produced synthesis gas2907 may be provided to catalytic methanation process unit 2914 that maybe configured to produce natural gas 2916. Produced synthesis gas 2907may also be provided to methanol production unit 2918 to producemethanol 2920. Furthermore, produced synthesis gas 2907 may be providedto process unit 2922 for production of ammonia and/or urea 2924, andfuel cell 2926 that may be configured to produce electricity 2928.Synthesis gas 2907 may also be routed to power generation unit 2930,such as a turbine or combustor, to produce electricity 2932.

[0796]FIG. 74 illustrates an example of a square pattern of heat sources3000 and production wells 3002. Heat sources 3000 are disposed atvertices of squares 3010. Production well 3002 is placed in a center ofevery third square in both x- and y-directions. Midlines 3006 are formedequidistant to two production wells 3002, and perpendicular to a lineconnecting such production wells. Intersections of midlines 3006 atvertices 3008 form unit cell 3012. Heat source 3000 b and heat source3000 c are only partially within unit cell 3012. Only the one-halffraction of heat source 3000 b and the one-quarter fraction of heatsource 3000 c within unit cell 3012 are configured to provide heatwithin unit cell 3012. The fraction of heat source 3000 outside of unitcell 3012 is configured to provide heat outside of unit cell 3012. Thenumber of heat sources 3000 within one unit cell 3012 is a ratio of heatsources 3000 per production well 3002 within the formation.

[0797] The total number of heat sources inside unit cell 3012 isdetermined by the following method:

[0798] (a) 4 heat sources 3000 a inside unit cell 3012 are counted asone heat source each;

[0799] (b) 8 heat sources 3000 b on midlines 3006 are counted asone-half heat source each; and

[0800] (c) 4 heat sources 3000 c at vertices 3008 are counted asone-quarter heat source each.

[0801] The total number of heat sources is determined from adding theheat sources counted by, (a) 4, (b) 8/2=4, and (c) 4/4=1, for a totalnumber of 9 heat sources 3000 in unit cell 3012. Therefore, a ratio ofheat sources 3000 to production wells 3002 is determined as 9:1 for thepattern illustrated in FIG. 74.

[0802]FIG. 75 illustrates an example of another pattern of heat sources3000 and production wells 3002. Midlines 3006 are formed equidistantfrom the two production wells 3002, and perpendicular to a lineconnecting such production wells. Unit cell 3014 is determined byintersection of midlines 3006 at vertices 3008. Twelve heat sources 3000are counted in unit cell 3014 by a method as described in the aboveembodiments, of which are six are whole sources of heat, and six are onethird sources of heat (with the other two thirds of heat from such sixwells going to other patterns). Thus, a ratio of heat sources 3000 toproduction wells 3002 is determined as 8:1 for the pattern illustratedin FIG. 75. An example of a pattern of heat sources is illustrated inU.S. Pat. No. 2,923,535 issued to Ljungstrom, which is incorporated byreference as if fully set forth herein.

[0803] In certain embodiments, a triangular pattern of heat sources mayprovide advantages when compared to alternative patterns of heatsources, such as squares, hexagons, and hexagons with additional heatersinstalled halfway between the hexagon corners (12 to 1 pattern).Squares, hexagons, and the 12:1 patterns are disclosed in U.S. Pat. No.2,923,535 and/or in U.S. Pat. No. 4,886,118. For example, a triangularpattern of heat sources may provide more uniform heating of ahydrocarbon containing formation resulting from a more uniformtemperature distribution of an area of a formation heated by the patternof heat sources.

[0804]FIG. 76 illustrates an embodiment of triangular pattern 3100 ofheat sources 3102. FIG. 76a illustrates an embodiment of square pattern3101 of heat sources 3103. FIG. 77 illustrates an embodiment ofhexagonal pattern 3104 of heat sources 3106. FIG. 77a illustrates anembodiment of 12 to 1 pattern 3105 of heat sources 3107. A temperaturedistribution for all patterns may be determined by an analytical method.The analytical method may be simplified by analyzing only temperaturefields within “confined” patterns (e.g., hexagons), i.e., completelysurrounded by others. In addition, the temperature field may beestimated to be a superposition of analytical solutions corresponding toa single heat source.

[0805] The comparisons of patterns of heat sources were evaluated forthe same heater well density and the same heating input regime. Forexample, a number of heat sources per unit area in a triangular patternis the same as the number of heat sources per unit area in the 10 mhexagonal pattern if the space between heat sources is increased toabout 12.2 m in the triangular pattern. The equivalent spacing for asquare pattern would be 11.3 m, while the equivalent spacing for a 12 to1 pattern would be 15.7 m.

[0806]FIG. 78 illustrates temperature profile 3110 after three years ofheating for a triangular pattern with a 12.2 m spacing in a typicalGreen River oil shale. The triangular pattern may be configured as shownin FIG. 76. Temperature profile 3110 is a three-dimensional plot oftemperature versus a location within a triangular pattern. FIG. 79illustrates temperature profile 3108 after three years of heating for asquare pattern with 11.3 m spacing in a typical Green River oil shale.Temperature profile 3108 is a three-dimensional plot of temperatureversus a location within a square pattern. The square pattern may beconfigured as shown in FIG. 76a. FIG. 79a illustrates temperatureprofile 3109 after three years of heating for a hexagonal pattern with10.0 m spacing in a typical Green River oil shale. Temperature profile3109 is a three-dimensional plot of temperature versus a location withina hexagon pattern. The hexagonal pattern may be configured as shown inFIG. 77.

[0807] As shown in a comparison of FIGS. 78, 79 and 79 a, a temperatureprofile of the triangular pattern is more uniform than a temperatureprofile of the square or hexagonal pattern. For example, a minimumtemperature of the square pattern is approximately 280° C., and aminimum temperature of the hexagonal pattern is approximately 250° C. Incontrast, a minimum temperature of the triangular pattern isapproximately 300° C. Therefore, a temperature variation within thetriangular pattern after 3 years of heating is 20° C. less than atemperature variation within the square pattern and 50° C. less than atemperature variation within the hexagonal pattern. For a chemicalprocess, where reaction rate is proportional to an exponent oftemperature, even a 20° C. difference is substantial.

[0808]FIG. 80 illustrates a comparison plot between the average patterntemperature (in degrees Celsius) and temperatures at the coldest spotsfor each pattern, as a function of time (in years). The coldest spot foreach pattern is located at a pattern center (centroid). As shown in FIG.76, the coldest spot of a triangular pattern is point 3118, while point3117 is the coldest spot of a square pattern, as shown in FIG. 76a. Asshown in FIG. 77, the coldest spot of a hexagonal pattern is point 3114,while point 3115 is the coldest spot of a 12 to 1 pattern, as shown inFIG. 77a. The difference between an average pattern temperature andtemperature of the coldest spot represents how uniform the temperaturedistribution for a given pattern is. The more uniform the heating, thebetter the product quality that may be made. The larger the volumefraction of resource that is overheated, the more undesirable productcomposition will be made.

[0809] As shown in FIG. 80, the difference between an averagetemperature 3120 of a pattern and temperature of the coldest spot isless for the triangular pattern 3118 than for square pattern 3117,hexagonal pattern 3114, or 12 to 1 pattern 3115. Again, there is asubstantial difference between triangular and hexagonal patterns.

[0810] Another way to assess the uniformity of temperature distributionis to compare temperatures of the coldest spot of a pattern with a pointlocated at the center of a side of a pattern midway between heaters. Asshown in FIG. 77, point 3112 is located at the center of a side of thehexagonal pattern midway between heaters. As shown in FIG. 76, point3116 is located at the center of a side of a triangular pattern midwaybetween heaters. Point 3119 is located at the center of a side of thesquare pattern midway between heaters, as shown in FIG. 76a.

[0811]FIG. 81 illustrates a comparison plot between the average patterntemperature (in degrees Celsius), 3120 temperatures at coldest spot 3118for triangular patterns, coldest spot 3114 for hexagonal patterns, point3116 located at the center of a side of triangular pattern midwaybetween heaters, and point 3112 located at the center of a side ofhexagonal pattern midway between heaters, as a function of time (inyears). FIG. 81a illustrates a comparison plot between the averagepattern temperature 3120 (in degrees Celsius), temperatures at coldestspot 3117 and point 3119 located at the center of a side of a patternmidway between heaters, as a function of time (in years), for a squarepattern.

[0812] As shown in a comparison of FIGS. 81 and 81a, for each pattern, atemperature at a center of a side midway between heaters is higher thana temperature at a center of the pattern. A difference between atemperature at a center of a side midway between heaters and a center ofthe hexagonal pattern increases substantially during the first year ofheating, and stays relatively constant afterward. A difference between atemperature at an outer lateral boundary and a center of the triangularpattern, however, is negligible. Therefore, a temperature distributionin a triangular pattern is substantially more uniform than a temperaturedistribution in a hexagonal pattern. A square pattern also provides moreuniform temperature distribution than a hexagonal pattern, however it isstill less uniform than a temperature distribution in a triangularpattern.

[0813] A triangular pattern of heat sources may have, for example, ashorter total process time than a square, hexagonal or 12 to 1 patternof heat sources for the same heater well density. A total process timemay include a time required for an average temperature of a heatedportion of a formation to reach a target temperature and a time requiredfor a temperature at a coldest spot within the heated portion to reachthe target temperature. For example, heat may be provided to the portionof the formation until an average temperature of the heated portionreaches the target temperature. After the average temperature of theheated portion reaches the target temperature, an energy supply to theheat sources may be reduced such that less or minimal heat may beprovided to the heated portion. An example of a target temperature maybe approximately 340° C. The target temperature, however, may varydepending on, for example, formation composition and/or formationconditions such as pressure.

[0814]FIG. 81b illustrates a comparison plot between the average patterntemperature and temperatures at the coldest spots for each pattern, as afunction of time when heaters are turned off after the averagetemperature reaches a target value. As shown in FIG. 81b, an averagetemperature of the formation reaches a target temperature inapproximately 3 years (about 340° C.). As shown in FIG. 81b, atemperature at the coldest point within the triangular pattern reachesthe target temperature (about 340° C.) 0.8 years later. In this manner,a total process time for such a triangular pattern is about 3.8 yearswhen the heat input is discontinued when the target average temperatureis reached. As shown in FIG. 81b, a temperature at the coldest pointwithin the triangular pattern reaches the target temperature (about 340°C.) before a temperature at the coldest point within the square patternor a temperature at the coldest point within the hexagonal patternreaches the target temperature. A temperature at the coldest pointwithin the hexagonal pattern, however, reaches the target temperatureafter an additional time of about 2 years when the heaters are turnedoff upon reaching the target average temperature. Therefore, a totalprocess time for a hexagonal pattern is about 5.0 years. In this manner,a total process time for heating a portion of a formation with atriangular pattern is 1.2 years less (approximately 25%) than a totalprocess time for heating a portion of a formation with a hexagonalpattern. In a preferred mode, the power to the heaters may be reduced orturned off when the average temperature of the pattern reaches a targetlevel. This prevents overheating the resource, which wastes energy andproduces lower product quality. The triangular pattern has the mostuniform temperatures and the least overheating. Although a capital costof such a triangular pattern may be approximately the same as a capitalcost of the hexagonal pattern, the triangular pattern may accelerate oilproduction and requires a shorter total process time. In this manner,such a triangular pattern may be more economical than a hexagonalpattern.

[0815] A spacing of heat sources in a triangular pattern, which mayyield the same process time as a hexagonal pattern having about a 10.0 mspace between heat sources, may be equal to approximately 14.3 m. Inthis manner, the total process time of a hexagonal pattern may beachieved by using about 26% less heat sources than may be included insuch a hexagonal pattern. In this manner, such a triangular pattern mayhave substantially lower capital and operating costs. As such, thistriangular pattern may also be more economical than a hexagonal pattern.

[0816]FIG. 12 depicts an embodiment of a natural distributed combustor.In one experiment the embodiment schematically shown in FIG. 12 was usedto heat high volatile bituminous C coal in situ. A heating well wasconfigured to be heated with electrical resistance heaters and/or anatural distributed combustor such as is schematically shown in FIG. 12.Thermocouples were located every 2 feet along the length of the naturaldistributed combustor (along conduit 532 as is schematically shown inFIG. 12). The coal was first heated with electrical resistance heatersuntil pyrolysis was complete proximate the well. FIG. 130 depicts squaredata points measured during electrical resistance heating at variousdepths in the coal after the temperature profile had stabilized (thecoal seam was about 16 feet thick starting at about 28 feet of depth).At this point heat energy was being supplied at about 300 Watts perfoot. Air was subsequently injected via conduit 532 at graduallyincreasing rates, and electric power was substantially simultaneouslydecreased. Combustion products were removed from the reaction zone in anannulus surrounding conduit 532 and the electrical resistance heater.The electric power was decreased at rates that would approximatelyoffset heating provided by the combustion of the coal caused by thenatural distributed combustor. Air rates were increased, and power rateswere decreased, over a period of about 2 hours until no electric powerwas being supplied. FIG. 130 depicts diamond data points measured duringnatural distributed combustion heating (without any electricalresistance heating) at various depths in the coal after the temperatureprofile had stabilized. As can be seen in FIG. 130, the naturaldistributed combustion heating provided a temperature profile that iscomparable to the electrical resistance temperature profile. Thisexperiment demonstrated that natural distributed combustors can provideformation heating that is comparable to the formation heating providedby electrical resistance heaters. This experiment was repeated atdifferent temperatures, and in two other wells, all with similarresults.

[0817] Numerical calculations have been made for a natural distributedcombustor system configured to heat a hydrocarbon containing formation.A commercially available program called PRO-II was used to make examplecalculations based on a conduit of diameter 6.03 cm with a wallthickness of 0.39 cm. The conduit was disposed in an opening in theformation with a diameter of 14.4 cm. The conduit had critical floworifices of 1.27 mm diameter spaced 183 cm apart. The conduit wasconfigured to heat a formation of 91.4 meters thick. A flow rate of airwas 1.70 standard cubic meters per minute through the critical floworifices. A pressure of air at the inlet of the conduit was 7 barsabsolute. Exhaust gases had a pressure of 3.3 bars absolute. A heatingoutput of 1066 watts per meter was used. A temperature in the openingwas set at 760° C. The calculations determined a minimal pressure dropwithin the conduit of about 0.023 bar. The pressure drop within theopening was less than 0.0013 bar.

[0818]FIG. 82 illustrates extension (in meters) of a reaction zonewithin a coal formation over time (in years) according to the parametersset in the calculations. The width of the reaction zone increases withtime as the carbon was oxidized proximate to the center.

[0819] Numerical calculations have been made for heat transfer using aconductor-in-conduit heater. Calculations were made for a conductorhaving a diameter of about 1 inch (2.54 cm) disposed in a conduit havinga diameter of about 3 inches (7.62 cm). The conductor-in-conduit heaterwas disposed in an opening of a carbon containing formation having adiameter of about 6 inches (15.24 cm). An emissivity of the carboncontaining formation was maintained at a value of 0.9, which is expectedfor geological materials. The conductor and the conduit were givenalternate emissivity values of high emissivity (0.86), which is commonfor oxidized metal surfaces, and low emissivity (0.1), which is forpolished and/or un-oxidized metal surfaces. The conduit was filled witheither air or helium. Helium is known to be a more thermally conductivegas than air. The space between the conduit and the opening was filledwith a gas mixture of methane, carbon dioxide, and hydrogen gases. Twodifferent gas mixtures were used. The first gas mixture had molefractions of 0.5 for methane, 0.3 for carbon dioxide, and 0.2 forhydrogen. The second gas mixture had mole fractions of 0.2 for methane,0.2 for carbon dioxide, and 0.6 for hydrogen.

[0820]FIG. 83 illustrates a calculated ratio of conductive heat transferto radiative heat transfer versus a temperature of a face of thehydrocarbon containing formation in the opening for an air filledconduit. The temperature of the conduit was increased linearly from 93°C. to 871° C. The ratio of conductive to radiative heat transfer wascalculated based on emissivity values, thermal conductivities,dimensions of the conductor, conduit, and opening, and the temperatureof the conduit. Line 3204 is calculated for the low emissivity value(0.1). Line 3206 is calculated for the high emissivity value (0.86). Alower emissivity for the conductor and the conduit provides for a higherratio of conductive to radiative heat transfer to the formation. Thedecrease in the ratio with an increase in temperature may be due to areduction of conductive heat transfer with increasing temperature. Asthe temperature on the face of the formation increases, a temperaturedifference between the face and the heater is reduced, thus reducing atemperature gradient that drives conductive heat transfer.

[0821]FIG. 84 illustrates a calculated ratio of conductive heat transferto radiative heat transfer versus a temperature at a face of thehydrocarbon containing formation in the opening for a helium filledconduit. The temperature of the conduit was increased linearly from 93°C. to 871° C. The ratio of conductive to radiative heat transfer wascalculated based on emissivity values; thermal conductivities;dimensions of the conductor, conduit, and opening; and the temperatureof the conduit. Line 3208 is calculated for the low emissivity value(0.1). Line 3210 is calculated for the high emissivity value (0.86). Alower emissivity for the conductor and the conduit again provides for ahigher ratio of conductive to radiative heat transfer to the formation.The use of helium instead of air in the conduit significantly increasesthe ratio of conductive heat transfer to radiative heat transfer. Thismay be due to a thermal conductivity of helium being about 5.2 to about5.3 times greater than a thermal conductivity of air.

[0822]FIG. 85 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the hydrocarboncontaining formation for a helium filled conduit and a high emissivityof 0.86. The opening has a gas mixture equivalent to the second mixturedescribed above having a hydrogen mole fraction of 0.6. Openingtemperature 3216 was linearly increased from 93° C. to 871° C. Openingtemperature 3216 was assumed to be the same as the temperature at theface of the hydrocarbon containing formation. Conductor temperature 3212and conduit temperature 3214 were calculated from opening temperature3216 using the dimensions of the conductor, conduit, and opening, valuesof emissivities for the conductor, conduit, and face, and thermalconductivities for gases (helium, methane, carbon dioxide, andhydrogen). It may be seen from the plots of temperatures of theconductor, conduit, and opening for the conduit filled with helium, thatat higher temperatures approaching 871° C., the temperatures of theconductor, conduit, and opening begin to substantially equilibrate.

[0823]FIG. 86 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the hydrocarboncontaining formation for an air filled conduit and a high emissivity of0.86. The opening has a gas mixture equivalent to the second mixturedescribed above having a hydrogen mole fraction of 0.6. Openingtemperature 3216 was linearly increased from 93° C. to 871° C. Openingtemperature 3216 was assumed to be the same as the temperature at theface of the hydrocarbon containing formation. Conductor temperature 3212and conduit temperature 3214 were calculated from opening temperature3216 using the dimensions of the conductor, conduit, and opening, valuesof emissivities for the conductor, conduit, and face, and thermalconductivities for gases (air, methane, carbon dioxide, and hydrogen).It may be seen from the plots of temperatures of the conductor, conduit,and opening for the conduit filled with air, that at higher temperaturesapproaching 871° C., the temperatures of the conductor, conduit, andopening begin to substantially equilibrate, as seen for the heliumfilled conduit with high emissivity.

[0824]FIG. 87 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the hydrocarboncontaining formation for a helium filled conduit and a low emissivity of0.1. The opening has a gas mixture equivalent to the second mixturedescribed above having a hydrogen mole fraction of 0.6. Openingtemperature 3216 was linearly increased from 93° C. to 871° C. Openingtemperature 3216 was assumed to be the same as the temperature at theface of the hydrocarbon containing formation. Conductor temperature 3212and conduit temperature 3214 were calculated from opening temperature3216 using the dimensions of the conductor, conduit, and opening, valuesof emissivities for the conductor, conduit, and face, and thermalconductivities for gases (helium, methane, carbon dioxide, andhydrogen). It may be seen from the plots of temperatures of theconductor, conduit, and opening for the conduit filled with helium, thatat higher temperatures approaching 871° C., the temperatures of theconductor, conduit, and opening do not begin to substantiallyequilibrate as seen for the high emissivity example shown in FIG. 85.Also, higher temperatures in the conductor and the conduit are neededfor an opening and face temperature of 871° C. than as for the exampleshown in FIG. 85. Thus, increasing an emissivity of the conductor andthe conduit may be advantageous in reducing operating temperaturesneeded to produce a desired temperature in a hydrocarbon containingformation. Such reduced operating temperatures may allow for the use ofless expensive alloys for metallic conduits.

[0825]FIG. 88 illustrates temperatures of the conductor, the conduit,and the opening versus a temperature at a face of the hydrocarboncontaining formation for an air filled conduit and a low emissivity of0.1. The opening has a gas mixture equivalent to the second mixturedescribed above having a hydrogen mole fraction of 0.6. Openingtemperature 3216 was linearly increased from 93° C. to 871° C. Openingtemperature 3216 was assumed to be the same as the temperature at theface of the hydrocarbon containing formation. Conductor temperature 3212and conduit temperature 3214 were calculated from opening temperature3216 using the dimensions of the conductor, conduit, and opening, valuesof emissivities for the conductor, conduit, and face, and thermalconductivities for gases (air, methane, carbon dioxide, and hydrogen).It may be seen from the plots of temperatures of the conductor, conduit,and opening for the conduit filled with helium, that at highertemperatures approaching 871° C., the temperatures of the conductor,conduit, and opening do not begin to substantially equilibrate as seenfor the high emissivity example shown in FIG. 86. Also, highertemperatures in the conductor and the conduit are needed for an openingand face temperature of 871° C. than as for the example shown in FIG.86. Thus, increasing an emissivity of the conductor and the conduit maybe advantageous in reducing operating temperatures needed to produce adesired temperature in a hydrocarbon containing formation. Such reducedoperating temperatures may provide for a lesser metallurgical costassociated with materials that require less substantial temperatureresistance (e.g., a lower melting point).

[0826] Calculations were also made using the first mixture of gas havinga hydrogen mole fraction of 0.2. The calculations resulted insubstantially similar results to those for a hydrogen mole fraction of0.6.

[0827]FIG. 89 depicts a retort and collection system used to conductcertain experiments. Retort vessel 3314 was a pressure vessel of 316stainless steel configured to hold a material to be tested. The vesseland appropriate flow lines were wrapped with a 0.0254 meters by 1.83meters electric heating tape. The wrapping was configured to providesubstantially uniform heating throughout the retort system. Thetemperature was controlled by measuring a temperature of the retortvessel with a thermocouple and altering the temperature of the vesselwith a proportional controller. The heating tape was further wrappedwith insulation as shown. The vessel sat on a 0.0508 meters thickinsulating block heated only from the sides. The heating tape extendedpast the bottom of the stainless steel vessel to counteract heat lossfrom the bottom of the vessel.

[0828] A 0.00318 m stainless steel dip tube 3312 was inserted throughmesh screen 3310 and into the small dimple on the bottom of vessel 3314.Dip tube 3312 was slotted at the bottom so that solids could not plugthe tube and prevent removal of the products. Screen 3310 was supportedalong the cylindrical wall of the vessel by a small ring having athickness of about 0.00159 m. Therefore, the small ring provides a spacebetween an end of dip tube 3312 and a bottom of vessel 3314 which alsoinhibited solids from plugging the dip tube. A thermocouple was attachedto the outside of the vessel to measure a temperature of the steelcylinder. The thermocouple was protected from direct heat of the heaterby a layer of insulation. An air-operated diaphragm-type backpressurevalve 3304 was provided for tests at elevated pressures. The products atatmospheric pressure pass into conventional glass laboratory condenser3320. Coolant disposed in the condenser 3320 was chilled water having atemperature of about 1.7° C. The oil vapor and steam products condensedin the flow lines of the condenser and flowed into the graduated glasscollection tube. A volume of produced oil and water was measuredvisually. Non-condensable gas flowed from condenser 3320 through gasbulb 3316. Gas bulb 3316 has a capacity of 500 cm³. In addition, gasbulb 3316 was originally filled with helium. The valves on the bulb weretwo-way valves 3317 to provide easy purging of bulb 3316 and removal ofnon-condensable gases for analysis. Considering a sweep efficiency ofthe bulb, the bulb would be expected to contain a composite sample ofthe previously produced 1 to 2 liters of gas. Standard gas analysismethods were used to determine the gas composition. The gas exiting thebulb passed into collection vessel 3318 that is in water 3322 in waterbath 3324. The water bath 3324 was graduated to provide an estimate ofthe volume of the produced gas over a time of the procedure (the waterlevel changed, thereby indicating the amount of gas produced). Thecollection vessel 3318 also included an inlet valve at a bottom of thecollection system under water and a septum at a top of the collectionsystem for transfer of gas samples to an analyzer.

[0829] At location 3300 one or more gases may be injected into thesystem shown in FIG. 89 to pressurize, maintain pressure, or sweepfluids in the system. Pressure gauge 3302 may be used to monitorpressure in the system. Heating/insulating material 3306 (e.g.,insulation or a temperature control bath) may be used to regulate and/ormaintain temperatures. Controller 3308 may be used to control heating ofvessel 3314.

[0830] A final volume of gas produced is not the volume of gas collectedover water because carbon dioxide and hydrogen sulfide are soluble inwater. Analysis of the water has shown that the gas collection systemover water removes about one-half of the carbon dioxide produced in atypical experiment. The concentration of carbon dioxide in water affectsa concentration of the non-soluble gases collected over water. Inaddition, the volume of gas collected over water was found to vary fromabout one-half to two-thirds of the volume of gas produced.

[0831] The system was purged with about 5 to 10 pore volumes of heliumto remove all air and pressurized to about 20 bars absolute for 24 hoursto check for pressure leaks. Heating was then started slowly, takingabout 4 days to reach 260° C. After about 8 to 12 hours at 260° C., thetemperature was raised as specified by the schedule desired for theparticular test. Readings of temperature on the inside and outside ofthe vessel were recorded frequently to assure that the controller wasworking correctly.

[0832] In one experiment oil shale was tested in the system shown inFIG. 89. In this experiment, 270° C. was about the lowest temperature atwhich oil was generated at any appreciable rate. Thus, readings of oilcan begin at any time in this range. For water, production started atabout 100° C. and was monitored at all times during the run. For gas,various amounts were generated during the course of production.Therefore, monitoring was needed throughout the run.

[0833] The oil and water production was collected in 4 or 5 fractionsthroughout the run. These fractions were composite samples over aparticular time interval involved. The cumulative volume of oil andwater in each fraction was measured as it accrued. After each fractionwas collected, the oil was analyzed as desired. The density of the oilwas measured.

[0834] After the test, the retort was cooled, opened, and inspected forevidence of any liquid residue. A representative sample of the crushedshale loaded into the retort was taken and analyzed for oil generatingpotential by the Fischer Assay method. After the test, three samples ofspent shale in the retort were taken: one near the top, one at themiddle, and one near the bottom. These were tested for remaining organicmatter and elemental analysis.

[0835] Experimental data from the experiment described above was used todetermine a pressure-temperature relationship relating to the quality ofthe produced fluids. Varying the operating conditions included alteringtemperatures and pressures. Various samples of oil shale were pyrolyzedat various operating conditions. The quality of the produced fluids wasdescribed by a number of desired properties. Desired properties includedAPI gravity, an ethene to ethane ratio, an atomic carbon to atomichydrogen ratio, equivalent liquids produced (gas and liquid), liquidsproduced, percent of Fischer Assay, and percent of fluids with carbonnumbers greater than about 25. Based on data collected these equilibriumexperiments, families of curves for several values of each of theproperties were constructed as shown in FIGS. 90-96. From these figures,the following relationships were used to describe the functionalrelationship of a given value of a property:

P=exp[(A/T)+B],

A=a ₁*(property)³ +a ₂*(property)² +a ₃*(property)+a₄

B=b ₁*(property)³ +b ₂*(property)² +b ₃*(property)+b₄

[0836] The generated curves may be used to determine a preferredtemperature and a preferred pressure that may produce fluids withdesired properties. Data illustrating the pressure-temperaturerelationship of a number of the desired properties for Green River oilshale was plotted in a number of the following figures.

[0837] In FIG. 90, a plot of gauge pressure versus temperature isdepicted (in FIGS. 90-96 the pressure is indicated in bars). Linesrepresenting the fraction of products with carbon numbers greater thanabout 25 were plotted. For example, when operating at a temperature of375° C. and a pressure of 2.7 bars absolute, 15% of the produced fluidhydrocarbons had a carbon number equal to or greater than 25. At lowpyrolysis temperatures and high pressures, the fraction of producedfluids with carbon numbers greater than about 25 decreases. Therefore,operating at a high pressure and a pyrolysis temperature at the lowerend of the pyrolysis temperature zone tends to decrease the fraction offluids with carbon numbers greater than 25 produced from oil shale.

[0838]FIG. 91 illustrates oil quality produced from an oil shalecontaining formation as a function of pressure and temperature. Linesindicating different oil qualities, as defined by API gravity, areplotted. For example, the quality of the produced oil was 45° API whenpressure was maintained at about 6 bars absolute and a temperature wasabout 375° C. As described in above embodiments, low pyrolysistemperatures and relatively high pressures may produce a high APIgravity oil.

[0839]FIG. 92 illustrates an ethene to ethane ratio produced from an oilshale containing formation as a function of pressure and temperature.For example, at a pressure of 11.2 bars absolute and a temperature of375° C., the ratio of ethene to ethane is approximately 0.01. The volumeratio of ethene to ethane may predict an olefin to alkane ratio ofhydrocarbons produced during pyrolysis. To control olefin content,operating at lower pyrolysis temperatures and a higher pressure may bebeneficial. Olefin content in above described embodiments may be reducedby operating at low pyrolysis temperature and a high pressure.

[0840]FIG. 93 depicts the dependence of yield of equivalent liquidsproduced from an oil shale containing formation as a function oftemperature and pressure. Line 3340 represents the pressure-temperaturecombination at which 8.38×10⁻⁵ m³ of fluid per kilogram of oil shale (20gallons/ton). The pressure/temperature plot results in a line 3342 forthe production of total fluids per ton of oil shale equal to 1.05×10⁻⁵m³/kg (25 gallons/ton). Line 3344 illustrates that 1.21×10⁻⁴ m³ of fluidis produced from 1 kilogram of oil shale (30 gallons/ton). For example,at a temperature of about 325° C. and a pressure of about 8 barsabsolute the resulting equivalent liquids was 8.38×10⁻⁵ m³/kg. Astemperature of the retort increased and the pressure decreased the yieldof the equivalent liquids produced increased. Equivalent liquidsproduced was defined as the amount of liquid equivalent to the energyvalue of the produced gas and liquids.

[0841]FIG. 94 illustrates a plot of oil yield produced from treating anoil shale containing formation, measured as volume of liquids per ton ofthe formation, as a function of temperature and pressure of the retort.Temperature is illustrated in units of Celsius on the x-axis, andpressure is illustrated in units of bars absolute on the y-axis. Asshown in FIG. 94, the yield of liquid/condensable products increases astemperature of the retort increases and pressure of the retortdecreases. The lines on FIG. 94 correspond to different liquidproduction rates measured as the volume of liquids produced per weightof oil shale and are shown in Table 3. TABLE 3 LINE VOLUME PRODUCED/MASSOF OIL SHALE (m³/kg) 3350 5.84 × 10⁻⁵ 3352 6.68 × 10⁻⁵ 3354 7.51 × 10⁻⁵3356 8.35 × 10⁻⁵

[0842]FIG. 95 illustrates yield of oil produced from treating an oilshale containing formation expressed as a percent of Fischer assay as afunction of temperature and pressure. Temperature is illustrated inunits of degrees Celsius on the x-axis, and gauge pressure isillustrated in units of bars on the y-axis. Fischer assay was used as amethod for assessing a recovery of hydrocarbon condensate from the oilshale. In this case, a maximum recovery would be 100% of the Fischerassay. As the temperature decreased and the pressure increased, thepercent of Fischer assay yield decreased.

[0843]FIG. 96 illustrates hydrogen to carbon ratio of hydrocarboncondensate produced from an oil shale containing formation as a functionof a temperature and pressure. Temperature is illustrated in units ofdegrees Celsius on the x-axis, and pressure is illustrated in units ofbars on the y-axis. As shown in FIG. 96, a hydrogen to carbon ratio ofhydrocarbon condensate produced from an oil shale containing formationdecreases as a temperature increases and as a pressure decreases. Asdescribed in more detail with respect to other embodiments herein,treating an oil shale containing formation at high temperatures maydecrease a hydrogen concentration of the produced hydrocarboncondensate.

[0844]FIG. 97 illustrates the effect of pressure and temperature withinan oil shale containing formation on a ratio of olefins to paraffins.The relationship of the value of one of the properties (R) withtemperature has the same functional form as the pressure-temperaturerelationships previously discussed. In this case the property (R) can beexplicitly expressed as a function of pressure and temperature.

R=exp[F(P)/T)+G(P)]

F(p)=f ₁*(P)³ +f ₂*(P)² +f ₃*(P)+f ₄

G(p)=g ₁*(P)³ +g ₂*(P)² +g ₃*(P)+g ₄

[0845] wherein R a value of the property, T is the absolute temperature(in degrees Kelvin), F(P) and G(P) are functions of pressurerepresenting the slope and intercept of a plot of R versus 1/T.

[0846]FIG. 97 is an example of such a plot for olefin to paraffin ratio.Data from the above experiments were compared to data from othersources. Isobars were plotted on a temperature versus olefin to paraffinratio graph using data from a variety of sources. Data from the abovedescribed experiments included an isobar at 1 bar absolute 3360, 2.5bars absolute 3362, 4.5 bars absolute 3364, 7.9 bars absolute 3366, and14.8 bars absolute 3368. Additional data plotted included data from asurface retort, data from Ljungstrom 3361, and data from ex situ oilshale studies conducted by Lawrence Livermore Laboratories 3363. Asillustrated in FIG. 97, the olefin to paraffin ratio appears to increaseas the pyrolysis temperature increases. However, for a fixedtemperature, the ratio decreases rapidly with an increase in pressure.Higher pressures and lower temperatures appear to favor the lowestolefin to paraffin ratios. At a temperature of about 325° C. and apressure of about 4.5 bars absolute 3366, a ratio of olefins toparaffins was approximately 0.01. Pyrolyzing at reduced temperature andincreased pressure may decrease an olefin to paraffin ratio. Pyrolyzinghydrocarbons for a longer period of time, which may be accomplished byincreasing pressure within the system, tends to result in a loweraverage molecular weight oil. In addition, production of gas mayincrease and a non-volatile coke may be formed.

[0847]FIG. 98 illustrates a relationship between an API gravity of ahydrocarbon condensate fluid, the partial pressure of molecular hydrogenwithin the fluid, and a temperature within an oil shale containingformation. As illustrated in FIG. 98, as a partial pressure of hydrogenwithin the fluid increased, the API gravity generally increased. Inaddition, lower pyrolysis temperatures appear to have increased the APIgravity of the produced fluids. Maintaining a partial pressure ofmolecular hydrogen within a heated portion of a hydrocarbon containingformation may increase the API gravity of the produced fluids.

[0848] In FIG. 99, a quantity of oil liquids produced in m³ of liquidsper kg of oil shale containing formation is plotted versus a partialpressure of H₂. Also illustrated in FIG. 99 are various curves forpyrolysis occurring at different temperatures. At higher pyrolysistemperatures production of oil liquids was higher than at the lowerpyrolysis temperatures. In addition, high pressures tended to decreasethe quantity of oil liquids produced from an oil shale containingformation. Operating an in situ conversion process at low pressures andhigh temperatures may produce a higher quantity of oil liquids thanoperating at low temperatures and high pressures.

[0849] As illustrated in FIG. 100, an ethene to ethane ratio in theproduced gas increased with increasing temperature. In addition,application of pressure decreased the ethene to ethane ratiosignificantly. As illustrated in FIG. 100, lower temperatures and higherpressures decreased the ethene to ethane ratio. The ethene to ethaneratio is indicative of the olefin to paraffin ratio in the condensedhydrocarbons.

[0850]FIG. 101 illustrates an atomic hydrogen to atomic carbon ratio inthe hydrocarbon liquids. In general, lower temperatures and higherpressures increased the atomic hydrogen to atomic carbon ratio of theproduced hydrocarbon liquids.

[0851] A small-scale field experiment of the in-situ process in oilshale was conducted. An objective of this test was to substantiatelaboratory experiments that produced high quality crude utilizing thein-situ retort process.

[0852] As illustrated in FIG. 104, the field experiment consisted of asingle unconfined hexagonal seven spot pattern on eight foot spacing.Six heat injection wells 3600 drilled to a depth of 40 m contained 17 mlong heating elements that injected thermal energy into the formationfrom 21 m to 39 m. A single producer well 3602 in the center of thepattern captured the liquids and vapors from the in-situ retort. Threeobservation wells 3603 inside the pattern and one outside the patternrecorded formation temperatures and pressures. Six dewatering wells 3604surrounded the pattern on 6 m spacing and were completed in an activeaquifer below the heated interval (from 44 m to 61 m). FIG. 105 is across-sectional view of the field experiment. A producer well 3602includes pump 3614. The lower portion of producer well 3602 was packedwith gravel. The upper portion of producer well 3602 was cemented.Heater well 3600 was located a distance of approximately 2.4 meters fromproducer well 3602. A heating element was located within the heater welland the heater well was cemented in place. Dewatering wells 3604 werelocated approximately 4.0 meters from heater wells 3600.

[0853] Produced oil, gas and water were sampled and analyzed throughoutthe life of the experiment. Surface and subsurface pressures andtemperatures and energy injection data were captured electronically andsaved for future evaluation. The composite oil produced from the testhad a 36° API gravity with a low olefin content of 1.1% by weight and aparaffin content of 66% by weight. The composite oil also included asulfur content of 0.4% by weight. This condensate-like crude confirmedthe quality predicted from the laboratory experiments. The compositionof the gas changed throughout the test. The gas was high in hydrogen(average approximately 25 mol %) and CO₂ (average approximately 15 mol%) as expected.

[0854] Evaluation of the post heat core indicates that the mahogany zonewas thoroughly retorted except for the top and bottom 1 m to 1.2 m. Oilrecovery efficiency was shown to be in the 75% to 80% range. Someretorting also occurred at least two feet outside of the pattern. Duringthe ICP experiment, the formation pressures were monitored with pressuremonitoring wells. The pressure increased to a highest pressure at 9.4bars absolute and then slowly declined. The high oil quality wasproduced at the highest pressure and temperatures below 350° C. Thepressure was allowed to decrease to atmospheric as temperaturesincreased above 370° C. As predicted, the oil composition under theseconditions was shown to be of lower API gravity, higher molecularweight, greater carbon numbers in carbon number distribution, higherolefin content, and higher sulfur and nitrogen contents.

[0855]FIG. 106 illustrates a plot of the maximum temperatures withineach of the three inner-most observation wells 3603 (see FIG. 104)versus time. The temperature profiles were very similar for the threeobservation wells. Heat was provided to the oil shale containingformation for 216 days. As illustrated in FIG. 106, the temperature atthe observer wells increased steadily until the heat was turned off.

[0856]FIG. 175 illustrates a plot of hydrocarbon liquids production, inbarrels per day, for the same in situ experiment. In this figure theline marked as “Separator Oil” indicates the hydrocarbon liquids thatwere produced after the produced fluids were cooled to ambientconditions and separated. In this figure the line marked as “Oil &C5+Gas Liquids” includes the hydrocarbon liquids produced after theproduced fluids were cooled to ambient conditions and separated and, inaddition, the assessed C₅ and heavier compounds that were flared. Thetotal liquid hydrocarbons produced to a stock tank during the experimentwas 194 barrels. The total equivalent liquid hydrocarbons produced(including the C₅ and heavier compounds) was 250 barrels. As indicatedin FIG. 175 the heat was turned off at day 216, however somehydrocarbons continued to be produced thereafter.

[0857]FIG. 176 illustrates a plot of production of hydrocarbon liquids(in barrels per day), gas (in MCF per day), and water (in barrels perday), versus heat energy injected (in mega Watt-hours), during the samein situ experiment. As shown in FIG. 176 the heat was turned off afterabout 440 megawatt-hours of energy had been injected.

[0858] As illustrated in FIG. 107, pressure within the oil shalecontaining material showed some variations initially at differentdepths, however over time these variations equalized. FIG. 107 depictsthe gauge fluid pressure in the observation well 3603 versus timemeasured in days at a radial distance of 2.1 m from the production well3602. The fluid pressures were monitored at depths of 24 m and 33 m.These depths corresponded to a richness within the oil shale containingmaterial of 8.3×10⁻⁵ m³ of oil/kg of oil shale at 24 m and 1.7×10⁻⁴ m³of oil/kg of oil shale at 33 m. The higher pressures initially observedat 33 m may be the result of a higher generation of fluids due to therichness of the oil shale containing material at that depth. Inaddition, at lower depths a lithostatic pressure may be higher, causingthe oil shale containing material at 33 m to fracture at higher pressurethan at 24 m. During the course of the experiment, pressures within theoil shale containing formation equalized. The equalization of thepressure may have resulted from fractures forming within the oil shalecontaining formation.

[0859]FIG. 108 is a plot of API gravity versus time measured in days. Asillustrated in FIG. 108, the API gravity was relatively high (i.e.,hovering around 40° until about 140 days). The API gravity, although itstill varied, decreased steadily thereafter. Prior to 110 days thepressure measured at shallower depths was increasing, and after 110 daysit began to decrease significantly. At about 140 days the pressure atthe deeper depths began to decrease. At about 140 days the temperatureas measured at the observation wells increased above about 370° C.

[0860] In FIG. 109 average carbon numbers of the produced fluid areplotted versus time measured in days. At approximately 140 days, theaverage carbon number of the produced fluids increased. Thisapproximately corresponded to the temperature rise and the drop inpressure illustrated in FIG. 106 and FIG. 107, respectively. Inaddition, as demonstrated in FIG. 110 the density of the producedhydrocarbon liquids, in grams per cc, increased at approximately 140days. The quality of the produced hydrocarbon liquids as demonstrated inFIG. 108, FIG. 109, and FIG. 110 decreased as the temperature increasedand the pressure decreased.

[0861]FIG. 111 depicts a plot of the weight percent of specific carbonnumbers of hydrocarbons within the produced hydrocarbon liquids. Thevarious curves represent different times at which the liquids wereproduced. The carbon number distribution of the produced hydrocarbonliquids for the first 136 days exhibited a relatively narrow carbonnumber distribution, with a low weight percent of carbon numbers above16. The carbon number distribution of the produced hydrocarbon liquidsbecomes progressively broader as time progresses after 136 days (e.g.,from 199 days to 206 days to 231 days). As the temperature continued toincrease, and the pressure had decreased towards one atmosphereabsolute, the product quality steadily deteriorated.

[0862]FIG. 112 illustrates a plot of the weight percent of specificcarbon numbers of hydrocarbons within the produced hydrocarbon liquids.Curve 3620 represents the carbon distribution for the composite mixtureof hydrocarbon liquids over the entire in situ conversion process(“ICP”) field experiment. For comparison, a plot of the carbon numberdistribution for hydrocarbon liquids produced from a surface retort ofthe same Green River oil shale is also depicted as curve 3622. In thesurface retort, oil shale was mined, placed in a vessel, rapidly heatedat atmospheric pressure to a high temperature in excess of 500° C. Asillustrated in FIG. 112, a carbon number distribution of the majority ofthe hydrocarbon liquids produced from the ICP field experiment waswithin a range of 8 to 15. The peak carbon number from production of oilduring the ICP field experiment was about 13. In contrast, the surfaceretort 3622 has a relatively flat carbon number distribution with asubstantial amount of carbon numbers greater than 25.

[0863] During the ICP experiment, the formation pressures were monitoredwith pressure monitoring wells. The pressure increased to a highestpressure at 9.3 bars absolute and then slowly declined. The high oilquality was produced at the highest pressures and temperatures below350° C. The pressure was allowed to decrease to atmospheric astemperatures increased above 370° C. As predicted, the oil compositionunder these conditions was shown to be of lower API gravity, highermolecular weight, greater carbon numbers in carbon number distribution,higher olefin content, and higher sulfur and nitrogen contents.

[0864] Experimental data from studies conducted by Lawrence LivermoreNational Laboratories (LLNL) was plotted along with laboratory data fromthe in situ conversion process (ICP) for an oil shale containingformation at atmospheric pressure in FIG. 113. The oil recovery as apercent of Fischer assay was plotted against a log of the heating rate.Data from LLNL 3642 included data derived from pyrolyzing powdered oilshale at atmospheric pressure and in a range from about 2 bars absoluteto about 2.5 bars absolute. As illustrated in FIG. 113, the data fromLLNL 3642 has a linear trend. Data from the ICP 3640 demonstrates thatoil recovery, as measured by Fischer assay, was much higher for ICP thanthe data from LLNL would suggest 3642. FIG. 113 demonstrates that oilrecovery from oil shale increases along an S-curve.

[0865] Results from the oil shale field experiment (e.g., measuredpressures, temperatures, produced fluid quantities and compositions,etc.) were inputted into a numerical simulation model in order toattempt to assess formation fluid transport mechanisms. FIG. 114 showsthe results from the computer simulation. In FIG. 114, oil production3670 in stock tank barrels/day was plotted versus time. Area 3674represents the liquid hydrocarbons in the formation at reservoirconditions that were measured in the field experiment. FIG. 114indicates that more than 90% of the hydrocarbons in the formation werevapors. Based on these results, and the fact that the wells in the fieldtest produced mostly vapors (until such vapors were cooled, at whichpoint hydrocarbon liquids were produced), it is believed thathydrocarbons in the formation move through the formation as vapors whenheated as is described above for the oil shale field experiment.

[0866] A series of experiments was conducted to determine the effects ofvarious properties of hydrocarbon containing formations on properties offluids produced from coal containing formations. The fluids may beproduced according to any of the embodiments as described herein. Theseries of experiments included organic petrography, proximate/ultimateanalyses, Rock-Eval pyrolysis, Leco Total Organic Carbon (“TOC”),Fischer Assay, and pyrolysis-gas chromatography. Such a combination ofpetrographic and chemical techniques may provide a quick and inexpensivemethod for determining physical and chemical properties of coal and forproviding a comprehensive understanding of the effect of geochemicalparameters on potential oil and gas production from coal pyrolysis. Theseries of experiments were conducted on forty-five cubes of coal todetermine source rock properties of each coal and to assess potentialoil and gas production from each coal.

[0867] Organic petrology is the study, mostly under the microscope, ofthe organic constituents of coal and other rocks. The petrography ofcoal is important since it affects the physical and chemical nature ofthe coal. The ultimate analysis refers to a series of defined methodsthat are used to determine the carbon, hydrogen, sulfur, nitrogen, ash,oxygen, and the heating value of a coal. Proximate analysis is themeasurement of the moisture, ash, volatile matter, and fixed carboncontent of a coal.

[0868] Rock-Eval pyrolysis is a petroleum exploration tool developed toassess the generative potential and thermal maturity of prospectivesource rocks. A ground sample may be pyrolyzed in a helium atmosphere.For example, the sample may be initially heated and held at atemperature of 300° C. for 5 minutes. The sample may be further heatedat a rate of 25° C./min to a final temperature of 600° C. The finaltemperature may be maintained for 1 minute. The products of pyrolysismay be oxidized in a separate chamber at 580° C to determined the totalorganic carbon content. All components generated may be split into twostreams passing through a flame ionization detector, which measureshydrocarbons, and a thermal conductivity detector, which measures CO₂.

[0869] Leco Total Organic Carbon (“TOC”) involves combustion of coal.For example, a small sample (about 1 gram) is heated to 1500° C. in ahigh-frequency electrical field under an oxygen atmosphere. Conversionof carbon to carbon dioxide is measured volumetrically. Pyrolysis-gaschromatography may be used for quantitative and qualitative analysis ofpyrolysis gas.

[0870] Coal of different ranks and vitrinite reflectances were treatedin a laboratory to simulate an in situ conversion process. The differentcoal samples were heated at a rate of about 2° C./day and at a pressureof 1 bar or 4.4 bars absolute. FIG. 115 shows weight percents ofparaffins plotted against vitrinite reflectance. As shown in FIG. 115,weight percent of paraffins in the produced oil increases at vitrinitereflectances of the coal below about 0.9%. In addition, a weight percentof paraffins in the produced oil approaches a maximum at a vitrinitereflectance of about 0.9%. FIG. 116 depicts weight percentages ofcycloalkanes in the produced oil plotted versus vitrinite reflectance.As shown in FIG. 116, a weight percent of cycloalkanes in the oilproduced increased as vitrinite reflectance increased. Weightpercentages of a sum of paraffins and cycloalkanes is plotted versusvitrinite reflectance in FIG. 117. In some embodiments, an in situconversion process may be utilized to produce phenol. Phenol generationmay increase when a fluid pressure within the formation is maintained ata lower pressure. Phenol weight percent in the produced oil is depictedin FIG. 118. A weight percent of phenol in the produced oil decreases asthe vitrinite reflectance increases. FIG. 119 illustrates a weightpercentage of aromatics in the hydrocarbon fluids plotted againstvitrinite reflectance. As shown in FIG. 119, a weight percent ofaromatics in the produced oil decreases below a vitrinite reflectance ofabout 0.9%. A weight percent of aromatics in the produced oil increasesabove a vitrinite reflectance of about 0.9%. FIG. 120 depicts a ratio ofparaffins to aromatics 3680 and a ratio of aliphatics to aromatics 3682plotted versus vitrinite reflectance. Both ratios increase to a maximumat a vitrinite reflectance between about 0.7% and about 0.9%. Above avitrinite reflectance of about 0.9%, both ratios decrease as vitrinitereflectance increases.

[0871]FIG. 134 depicts the condensable hydrocarbon compositions, andcondensable hydrocarbon API gravities, that were produced when variousranks of coal were treated as is described above for FIGS. 115-120. InFIG. 134, “SubC” means a rank of sub-bituminous C coal, “SubB” means arank of subbituminous B coal, “SubA” refers to a rank of sub- bituminousA coal, “HVC” refers to a rank of high volatile bituminous C coal,“HVB/A” refers to a rank of high volatile bituminous coal at the borderbetween B and A rank coal, “MV” refers to a rank medium volatilebituminous coal, and “Ro” refers to vitrinite reflectance. As can beseen in FIG. 134, certain ranks of coal will produce differentcompositions when treated in certain embodiments described herein. Forinstance, in many circumstances it may be desirable to treat coal havinga rank of HVB/A because such coal, when treated, has the highest APIgravity, the highest weight percent of paraffins, and the highest weightpercent of the sum of paraffins and cycloalkanes.

[0872] Results were also displayed as a yield of products. FIG. 121-124illustrate the yields of components in terms of m³ of product per kg ofhydrocarbon containing formation, when measure on a dry, ash free basis.As illustrated in FIG. 121 the yield of paraffins increased as thevitrinite reflectance of the coal increased. However, for coals with avitrinite reflectance greater than about 0.7 to 0.8% the yield ofparaffins fell off dramatically. In addition, a yield of cycloalkanesfollowed similar trends as the paraffins, increasing as the vitrinitereflectance of coal increased and decreasing for coals with a vitrinitereflectance greater than about 0.7% or 0.8% as illustrated in FIG. 122.FIG. 123 illustrates the increase of both paraffins and cycloalkanes asthe vitrinite reflectance of coal increases to about 0.7% or 0.8%. Asillustrated in FIG. 124, the yield of phenols may be relatively low forcoal containing material with a vitrinite reflectance of less than about0.3% and greater than about 1.25%. Production of phenols may be desireddue to the value of phenol as a feedstock for chemical synthesis.

[0873] As demonstrated in FIG. 125, the API gravity appears to increasesignificantly when the vitrinite reflectance is greater than about 0.4%.FIG. 126 illustrates the relationship between coal rank, (i.e.,vitrinite reflectance), and a yield of condensable hydrocarbons (ingallons per ton on a dry ash free basis) from a coal containingformation. The yield in this experiment appears to be in an optimalrange when the coal has a vitrinite reflectance greater than about 0.4%to less than about 1.3%.

[0874]FIG. 127 illustrates a plot of CO₂ yield of coal having variousvitrinite reflectances.

[0875] In FIGS. 127 and 128, CO₂ yield is set forth in weight percent ona dry ash free basis. As shown in FIG. 127, at least some CO₂ wasreleased from all of the coal samples. Such CO₂ production maycorrespond to various oxygenated functional groups present in theinitial coal samples. A yield of CO₂ produced from low-rank coal sampleswas significantly higher than a production from high-rank coal samples.Low-rank coals may include lignite and sub-bituminous brown coals.High-rank coals may include semi-anthracite and anthracite coal. FIG.128 illustrates a plot of CO₂ yield from a portion of a coal containingformation versus the atomic O/C ratio within a portion of a coalcontaining formation. As O/C atomic ratio increases, a CO₂ yieldincreases.

[0876] A slow heating process may produce condensed hydrocarbon fluidshaving API gravities in a range of 22° to 50°, and average molecularweights of about 150 g/gmol to about 250 g/gmol. These properties may becompared to properties of condensed hydrocarbon fluids produced by exsitu retorting of coal as reported in Great Britain Published PatentApplication No. GB 2,068,014 A, which is incorporated by reference as iffully set forth herein. For example, properties of condensed hydrocarbonfluids produced by an ex situ retort process include API gravities of1.9° to 7.9° produced at temperatures of 521° C. and 427° C.,respectively.

[0877] Table 4 shows a comparison of gas compositions, in percentvolume, obtained from in situ gasification of coal using air injectionto heat the coal, in situ gasification of coal using oxygen injection toheat the coal, and in situ gasification of coal in a reducing atmosphereby thermal pyrolysis heating as described in embodiments herein. TABLE 4Gasification Gasification Thermal Pyrolysis With Air With Oxygen HeatingH₂ 18.6% 35.5% 16.7% Methane 3.6% 6.9% 61.9% Nitrogen and Argon 47.5%0.0 0.0 Carbon Monoxide 16.5% 31.5% 0.9% Carbon Dioxide 13.1% 25.0% 5.3%Ethane 0.6% 1.1% 15.2%

[0878] As shown in Table 4, gas produced according to an embodimentdescribed herein may be treated and sold through existing natural gassystems. In contrast, gas produced by typical in situ gasificationprocesses may not be treated and sold through existing natural gassystems. For example, a heating value of the gas produced bygasification with air was 6000 KJ/m³, and a heating value of gasproduced by gasification with oxygen was 11,439 KJ/m. In contrast, aheating value of the gas produced by thermal conductive heating was39,159 KJ/m³.

[0879] Experiments were conducted to determine the difference betweentreating relatively large solid blocks of coal versus treatingrelatively small loosely packed particles of coal.

[0880] As illustrated in FIG. 129, coal 3700 in the shape of a cube washeated to pyrolyze the coal. Heat was provided to cube 3700 from heatsource 3704 inserted into the center of the cube and also from heatsources 3702 located on the sides of the cube. The cube was surroundedby insulation 3705. The temperature was raised simultaneously using heatsources 3704, 3702 at a rate of about 2° C./day at atmospheric pressure.Measurements from temperature gauges 3706 were used to determine anaverage temperature of cube 3700. Pressure in cube 3700 was monitoredwith pressure gauge 3708. The fluids produced from the cube of coal werecollected and routed through conduit 3709. Temperature of the productfluids was monitored with temperature gauge 3706 on conduit 3709. Apressure of the product fluids was monitored with pressure gauge 3708 onconduit 3709. A hydrocarbon condensate was separated from anon-condensable fluid in separator 3710. Pressure in separator 3710 wasmonitored with pressure gauge 3708. A portion of the non-condensablefluid was routed through conduit 3711 to gas analyzers 3712 forcharacterization. Grab samples were taken from a grab sample port 3714.Temperature of the non-condensable fluids was monitored with temperaturegauge 3706 on conduit 3711. A pressure of the non-condensable fluids wasmonitored with pressure gauge 3708 on conduit 3711. The remaining gaswas routed through a flow meter 3716, a carbon bed 3718, and vented tothe atmosphere. The produced hydrocarbon condensate was collected andanalyzed to determine the composition of the hydrocarbon condensate.

[0881]FIG. 102 illustrates a drum experimental apparatus. This apparatuswas used to test coal. Electrical heater 3404 and bead heater 3402 wereused to uniformly heat contents of drum 3400. Insulation 3405 surroundsdrum 3400. Contents of drum 3400 were heated at a rate of about 2°C./day at various pressures. Measurements from temperature gauges 3406were used to determine an average temperature in drum 3400. Pressure inthe drum was monitored with pressure gauge 3408. Product fluids wereremoved from drum 3400 through conduit 3409. Temperature of the productfluids was monitored with temperature gauge 3406 on conduit 3409. Apressure of the product fluids was monitored with pressure gauge 3408 onconduit 3409. Product fluids were separated in separator 3410. Separator3410 separated product fluids into condensable and non-condensableproducts. Pressure in separator 3410 was monitored with pressure gauge3408. Non-condensable product fluids were removed through conduit 3411.A composition of a portion of non-condensable product fluids removedfrom separator 3410 was determined by gas analyzer 3412. A portion ofcondensable product fluids were removed from separator 3410.Compositions of the portion of condensable product fluids collected weredetermined by external analysis methods. Temperature of thenon-condensable fluids was monitored with temperature gauge 3406 onconduit 3411. A pressure of the non-condensable fluids was monitoredwith pressure gauge 3408 on conduit 3411. Flow of non-condensable fluidsfrom separator 3410 was determined by flow meter 3416. Fluids measuredin flow meter 3416 were collected and neutralized in carbon bed 3418.Gas samples were collected in gas container 3414.

[0882] A large block of high volatile bituminous B Fruitland coal wasseparated into two portions. One portion (about 550 kg) was ground intosmall pieces and tested in a coal drum. The coal was ground to anapproximate diameter of about 6.34×10⁻⁴ m. The results of such testingare depicted with the circles in FIGS. 131 and 133. One portion (a cubehaving sides measuring 0.3048 m) was tested in a coal cube experiment.The results of such testing are depicted with the squares in FIGS. 131and 133.

[0883]FIG. 131 is a plot of gas phase compositions from experiments on acoal cube and a coal drum for H₂ 3724, methane 3726, ethane 3780,propane 3781, n-butane 3782, and other hydrocarbons 3783 as a functionof temperature. As can be seen for FIG. 131, the non condensable fluidsproduced from pyrolysis of the cube and the drum had similarconcentrations of the various hydrocarbons generated within the coal. InFIG. 131 these results were so similar that only one line was drawn forethane 3780, propane 3781, n-butane 3782, and other hydrocarbons 3783for both the cube and the drum results, and the two lines that weredrawn for H₂ (3724 a and 3724 b) and the two lines drawn for methane(3726 a and 3726 b) were in both instances very close to each other.Crushing the coal did not have an apparent effect on the pyrolysis ofthe coal. The peak in methane production 3726 occurred at about 450° C.At higher temperatures methane cracks to hydrogen, so the methaneconcentration decreases while the hydrogen content 3724 increases.

[0884]FIG. 132 illustrates a plot of cumulative production of gas as afunction of temperature from heating coal in the cube and coal in thedrum. Line 3790 represents gas production from coal in the drum and line3791 represents gas production from coal in the cube. As demonstrated byFIG. 132, the production of gas in both experiments yielded similarresults, even though the particle sizes were dramatically differentbetween the two experiments.

[0885]FIG. 133 illustrates cumulative condensable hydrocarbons producedin the cube and drum experiments. Line 3720 represents cumulativecondensable hydrocarbons production from the cube experiment, and line3722 represents cumulative condensable hydrocarbons production from thedrum experiment. As demonstrated by FIG. 133, the production ofcondensable hydrocarbons in both experiments yielded similar results,even though the particle sizes were dramatically different between thetwo experiments. Production of condensable hydrocarbons is substantiallycomplete when the temperature reached about 390° C. In both experimentsthe condensable hydrocarbons had an API gravity of about 37 degrees.

[0886] As shown in FIG. 131, methane started to be produced attemperature at or above about 270° C. Since the experiments wereconduced at atmospheric pressure, it is believed that the methane isproduced from the pyrolysis, and not from mere desorption. Between about270° C. and about 400° C., condensable hydrocarbons, methane and H₂ wereproduced as shown in FIGS. 131, 132, and 133. FIG. 131 shows that abovea temperature of about 400° C. methane and H₂ continue to be produced.Above about 450° C., however, methane concentration decreased in theproduced gases whereas the produced gases contained increased amounts ofH₂. If heating was continued, eventually all H₂ remaining in the coalwould be depleted, and production of gas from the coal would cease.FIGS. 131-133 indicate that the ratio of a yield of gas to a yield ofcondensable hydrocarbons will increase as the temperature increasesabove about 390° C.

[0887] FIGS. 131-133 demonstrate that particle size did notsubstantially affect the quality of condensable hydrocarbons producedfrom the treated coal, the quantity of condensable hydrocarbons producedfrom the treated coal, the amount of gas produced from the treated coal,the composition of the gas produced from the treated coal, the timerequired to produce the condensable hydrocarbons and gas from thetreated coal, or the temperatures required to produce the condensablehydrocarbons and gas from the treated coal. In essence a block of coalyielded substantially the same results from treatment as small particlesof coal. As such, it is believed that scale-up issues when treating coalwill not substantially affect treatment results.

[0888] An experiment was conducted to determine an effect of heating onthermal conductivity and thermal diffusivity of a portion of a coalcontaining formation. Thermal pulse tests performed in situ in a highvolatile bituminous C coal at the field pilot site showed a thermalconductivity between 2.0×10⁻³ to 2.39×10⁻³ cal/cm sec ° C. (0.85 to 1.0W/(m ° K)) at 20° C. Ranges in these values were due to differentmeasurements between different wells. The thermal diffusivity was4.8×10⁻³ cm²/s at 20° C. (the range was from about 4.1×10⁻³ to about5.7×10⁻³ cm²/s at 20° C.). It is believed that these measured values forthermal conductivity and thermal diffusivity are substantially higherthan would be expected based on literature sources (e.g., about threetimes higher in many instances).

[0889] An initial value for thermal conductivity from the in situexperiment is plotted versus temperature in FIG. 135 (this initial valueis point 3743 in FIG. 135). Additional points for thermal conductivity(i.e., all of the other values for line 3742 shown in FIG. 135) wereassessed by calculating thermal conductivities using temperaturemeasurements in all of the wells shown in FIG. 137, total heat inputfrom all heaters shown in FIG. 137, measured heat capacity and densityfor the coal being treated, gas and liquids production data (e.g.,composition, quantity, etc.), etc. For comparison, these assessedthermal conductivity values (see line 3742) were plotted with datareported in two papers from S. Badzioch, et al. (1964) and R. E. Glass(1984) (see line 3740). As illustrated in FIG. 135, the assessed thermalconductivities from the in situ experiment were higher than reportedvalues for thermal conductivities. The difference may be at leastpartially accounted for if it is assumed that the reported values do nottake into consideration the confined nature of the coal in an in situapplication. Because the reported values for thermal conductivity ofcoal are relatively low, they discourage the use of in situ heating forcoal.

[0890]FIG. 135 illustrates a decrease in the assessed thermalconductivity values 3742 at about 100° C. It is believed that thisdecrease in thermal conductivity was caused by water vaporizing in thecracks and void spaces (water vapor has a lower thermal conductivitythan liquid water). At about 350° C., the thermal conductivity began toincrease, and it increased substantially as the temperature increased to700° C. It is believed that the increases in thermal conductivity werethe result of molecular changes in the carbon structure. As the carbonwas heated it became more graphitic, which is illustrated in Table by anincreased vitrinite reflectance after pyrolysis. As void spacesincreased due to fluid production, heat was increasingly transferred byradiation and/or convection. In addition, concentrations of hydrogen inthe void spaces were raised due to pyrolysis and generation of synthesisgas.

[0891] Three data points 3744 of thermal conductivities under highstress were derived from laboratory tests on the same high volatilebituminous C coal used for the in situ field pilot site (see FIG. 135).In the laboratory tests a sample of such coal was stressed from alldirections, and heated relatively quickly. These thermal conductivitieswere determined at higher stress (i.e., 27.6 bars absolute), as comparedto the stress in the in situ field pilot (which were about 3 barsabsolute). Thermal conductivity values 3744 demonstrate that theapplication of stress increased the thermal conductivity of the coal attemperatures of 150° C., 250° C., and 350° C. It is believed that higherthermal conductivity values were obtained from stressed coal because thestress closed at least some cracks/void spaces and/or prevented newcracks/void spaces from forming.

[0892] Using the reported values for thermal conductivity and thermaldiffusivity of coal and a 12 m heat source spacing on an equilateraltriangle pattern, calculations show that a heating period of about tenyears would be needed to raise an average temperature of coal to about350° C. Such a heating period may not be economically viable. Usingexperimental values for thermal conductivity and thermal diffusivity andthe same 12 m heat source spacing, calculations show that the heatingperiod to reach an average temperature of 350° C. would be about 3years. The elimination of about 7 years of heating a formation will inmany instances significantly improve the economic viability of an insitu conversion process for coal.

[0893] Molecular hydrogen has a relatively high thermal conductivity(e.g., the thermal conductivity of molecular hydrogen is about 6 timesthe thermal conductivity of nitrogen or air). Therefore it is believedthat as the amount of hydrogen in the formation void spaces increases,the thermal conductivity of the formation will also increase. Theincreases in thermal conductivity due to the presence of hydrogen in thevoid spaces somewhat offsets decreases in thermal conductivity caused bythe void spaces themselves. It is believed that increases in thermalconductivity due to the presence of hydrogen will be larger for coalformations as compared to other hydrocarbon containing formations sincethe amount of void spaces created during pyrolysis will be larger (coalhas a higher hydrocarbon density, so pyrolysis creates more void spacesin coal).

[0894] Hydrocarbon fluids were produced from a portion of a coalcontaining formation by an in situ experiment conducted in a portion ofa coal containing formation. The coal was high volatile bituminous Ccoal. It was heated with electrical heaters. FIG. 136 illustrates across-sectional view of the in situ experimental field test system. Asshown in FIG. 136, the experimental field test system included at leastcoal containing formation 3802 within the ground and grout wall 3800.Coal containing formation 3802 dipped at an angle of approximately 36°with a thickness of approximately 4.9 meters. FIG. 137 illustrates alocation of heat sources 3804 a, 3804 b, 3804 c, production wells 3806a, 3806 b, and temperature observation wells 3803 a, 3808 b, 3808 c,3808 d used for the experimental field test system. The three heatsources were disposed in a triangular configuration. Production well3806 a was located proximate a center of the heat source pattern andequidistant from each of the heat sources. A second production well 3806b was located outside the heat source pattern and spaced equidistantfrom the two closest heat sources. Grout wall 3800 was formed around theheat source pattern and the production wells. The grout wall may includepillars 1-24. Grout wall 3800 was configured to inhibit an influx ofwater into the portion during the in situ experiment. In addition, groutwall 3800 was configured to substantially inhibit loss of generatedhydrocarbon fluids to an unheated portion of the formation.

[0895] Temperatures were measured at various times during the experimentat each of four temperature observation wells 3808 a, 3808 b, 3808 c,3808 d located within and outside of the heat source pattern asillustrated in FIG. 137. The temperatures measured (in degrees Celsius)at each of the temperature observation wells are displayed in FIG. 138as a function of time. Temperatures at observation wells 3808 a (3820),3808 b (3822), and 3808 c (3824) were relatively close to each other. Atemperature at temperature observation well 3808 d (3826) wassignificantly colder. This temperature observation well was locatedoutside of the heater well triangle illustrated in FIG. 137. This datademonstrates that in zones where there was little superposition of heattemperatures were significantly lower. FIG. 139 illustrated temperatureprofiles measured at the heat sources 3804 a (3830), 3804 b (3832), and3804 c (3834). The-temperature profiles were relatively uniform at theheat sources.

[0896]FIG. 140 illustrates a plot of cumulative volume (m³) of liquidhydrocarbons produced 3840 as a function of time (days). FIG. 149illustrates a plot of cumulative volume of gas produced 3910 in standardcubic feet, produced as a function of time (in days) for the same insitu experiment. Both FIG. 140 and FIG. 149 show the results during thepyrolysis stage only of the in situ experiment.

[0897]FIG. 141 illustrates the carbon number distribution of condensablehydrocarbons that were produced using slow, low temperature retortingprocess as described above. As can be seen in FIG. 141, relatively highquality products were produced during treatment. The results in FIG. 141are consistent with the results set forth in FIG. 146, which showresults from heating coal from the same formation in the laboratory forsimilar ranges of heating rates as were used in situ.

[0898] Table 5 illustrates the results from analyzing coal before andafter it was treated (including heating the temperatures set forth in asis set forth in FIG. 139 (i.e., after pyrolysis and production ofsynthesis gas) as described above. The coal was cored at about 11-1 1.3meters from the surface, midway into the coal bed, in both the “beforetreatment” and “after treatment” examples. Both cores were taken atabout the same location. Both cores were taken at about 0.66 meters fromwell 3804 c (between the grout wall and well 3804 c) in FIG. 137. In thefollowing Table 5 “FA” means Fisher Assay, “as rec'd” means the samplewas tested as it was received and without any further treatment,“Py-Water” means the water produced during pyrolysis, “H/C Atomic Ratio”means the atomic ratio of hydrogen to carbon, “daf” means “dry ashfree,” “dmmf” means “dry mineral matter free,” and “mmf” means “mineralmatter free.” The specific gravity of the “after treatment” core samplewas approximately 0.85 whereas the specific gravity of the “beforetreatment” core sample was approximately 1.35. TABLE 5 Before AfterAnalysis Treatment Treatment % Vitrinite Reflectance 0.54 5.16 FA(gal/ton, as-rec'd) 11.81 0.17 FA (wt %, as rec'd) 6.10 0.61 FA Py-Water(gal/ton, as-rec'd) 10.54 2.22 H/C Atomic Ratio 0.85 0.06 H (wt %, daf)5.31 0.44 O (wt %, daf) 17.08 3.06 N (wt %, daf) 1.43 1.35 Ash (wt %, asrec'd) 32.72 56.50 Fixed Carbon (wt %, dmmf) 54.45 94.43 Volatile Matter(wt %, dmmf) 45.55 5.57 Heating Value (Btu/lb, moist, mmf) 12048 14281

[0899] Even though the cores were taken outside the areas within thetriangle formed by the three heaters in FIG. 137, nevertheless the coresdemonstrate that the coal remaining in the formation changedsignificantly during treatment. The vitrinite reflectance results shownin Table 5 demonstrate that the rank of the coal remaining in theformation changed substantially during treatment. The coal was a highvolatile bituminous C coal before treatment. After treatment, however,the coal was essentially anthracite. The Fischer Assay results shown inTable 5 demonstrate that most of the hydrocarbons in the coal had beenremoved during treatment. The H/C Atomic Ratio demonstrates that most ofthe hydrogen in the coal had been removed during treatment. Asignificant amount of nitrogen and ash was left in the formation.

[0900] In sum, the results shown in Table 5 demonstrate that asignificant amount of hydrocarbons and hydrogen were removed duringtreatment of the coal by pyrolysis and generation of synthesis gas.Significant amounts of undesirable products (ash and nitrogen) remain inthe formation, while the significant amounts of desirable products(e.g., condensable hydrocarbons and gas) were removed.

[0901]FIG. 142 illustrates a plot of weight percent of a hydrocarbonproduced versus carbon number distribution for two laboratoryexperiments on coal from the field experiment site. The coal was a highvolatile bituminous C coal. As shown in FIG. 142, a carbon numberdistribution of fluids produced from a formation varied depending on,for example, pressure. For example, first pressure 3842 was about 1 barabsolute and second pressure 3844 was about 8 bars absolute. Thelaboratory carbon number distribution shown in FIG. 142 was similar tothat produced in the field experiment in FIG. 141 also at 1 barabsolute. As shown in FIG. 142, as pressure increased, a range of carbonnumbers of the hydrocarbon fluids decreased. An increase in productshaving carbon numbers less than 20 was observed when operating at 8 barsabsolute. Increasing the pressure from 1 bar absolute to 8 bars absolutealso increased an API gravity of the condensed hydrocarbon fluids. TheAPI gravities of condensed hydrocarbon fluids produced wereapproximately 23.1° and approximately 31.3°, respectively. Such anincrease in API gravity represents increased production of more valuableproducts.

[0902]FIG. 143 illustrates a bar graph of fractions from a boiling pointseparation of hydrocarbon liquids generated by a Fischer assay and aboiling point separation of hydrocarbon liquids from the coal cubeexperiment described herein (see, e.g., the system shown in FIG. 129).The experiment was conducted at a much slower heating rate (2 degreesCelsius per day) and the oil produced at a a lower final temperaturethan the Fischer Assay. FIG. 143 shows the weight percent of variousboiling point cuts of hydrocarbon liquids produced from a Fruitland highvolatile bituminous B coal. Different boiling point cuts may representdifferent hydrocarbon fluid compositions. The boiling point cutsillustrated include naphtha 3860 (initial boiling point to 166° C.), jetfuel 3862 (166° C. to 249° C.), diesel 3864 (249° C. to 370° C.), andbottoms 3866 (boiling point greater than 370° C.). The hydrocarbonliquids from the coal cube were substantially more valuable products.The API gravity of such hydrocarbon liquids was significantly greaterthan the API gravity of the Fischer Assay liquid. The hydrocarbonliquids from the coal cube also included significantly less residualbottoms than were produced from the Fischer Assay hydrocarbon liquids.

[0903]FIG. 144 illustrates a plot of percentage ethene, which is anolefin, to ethane produced from a coal formation as a function ofheating rate. Data points were derived from laboratory experimental data(see system shown in FIG. 89 and associated text) for slow heating ofhigh volatile bituminous C coal at atmospheric pressure, and fromFischer assay results. As illustrated in FIG. 144, the ratio of etheneto ethane increased as the heating rate increased. As such, it isbelieved that decreasing the heating rate of coal will decreaseproduction of olefins. The heating rate of a formation may be determinedin part by the spacings of heat sources within the formation, and by theamount of heat that is transferred from the heat sources to theformation.

[0904] Formation pressure may also have a significant effect on olefinproduction. A high formation pressure may tend to result in theproduction of small quantities of olefins. High pressure within aformation may result in a high H₂ partial pressure within the formation.The high H₂ partial pressure may result in hydrogenation of the fluidwithin the formation. Hydrogenation may result in a reduction of olefinsin a fluid produced from the formation. A high pressure and high H₂partial pressure may also result in inhibition of aromatization ofhydrocarbons within the formation. Aromatization may include formationof aromatic and cyclic compounds from alkanes and/or alkenes within ahydrocarbon mixture. If it is desirable to increase production ofolefins from a formation, the olefin content of fluid produced from theformation may be increased by reducing pressure within the formation.The pressure may be reduced by drawing off a larger quantity offormation fluid from a portion of the formation that is being produced.The pressure may be reduced by drawing a vacuum on the portion of theformation being produced.

[0905] The system depicted in FIG. 89, and the methods of using suchsystem (see other discussion herein with respect to using such system toconduct oil shale experiments) was used to conduct experiments on highvolatile bituminous C coal when such coal was heated at 5° C./day atatmospheric pressure. FIG. 103 depicts certain data points from suchexperiment (the line depicted in FIG. 103 was produced from a linearregression analysis of such data points). FIG. 103 illustrates theethene to ethane molar ratio as a function of hydrogen molarconcentration in non-condensable hydrocarbons produced from the coalduring the experiment. The ethene to ethane ratio in the non-condensablehydrocarbons is reflective of olefin content in all hydrocarbonsproduced from the coal. As can be seen in FIG. 103, as the concentrationof hydrogen autogenously increased during pyrolysis, the ratio of etheneto ethane decreased. It is believed that increases in the concentration(and partial pressure) of hydrogen during pyrolysis causes the olefinconcentration to decrease in the fluids produced from pyrolysis.

[0906]FIG. 145 illustrates product quality, as measured by API gravity,as a function of rate of temperature increase of fluids produced fromhigh volatile bituminous “C” coal. Data points were derived from Fischerassay data and from laboratory experiments. For the Fischer assay data,the rate of temperature increase was approximately 17,100° C./day andthe resulting API gravity was less than 11°. For the relatively slowlaboratory experiments, the rate of temperature increase ranged fromabout 2° C./day to about 10° C./day, and the resulting API gravitiesranged from about 23° to about 26°. A substantially linear decrease inquality (decrease in API gravity) was exhibited as the logarithmicheating rate increased.

[0907]FIG. 146 illustrates weight percentages of various carbon numbersproducts removed from high volatile bituminous “C” coal when coal isheated at various heating rates. Data points were derived fromlaboratory experiments and a Fischer assay. Curves for heating at a rateof 2° C./day 3870, 3° C./day 3872, 5° C./day 3874, and 10° C./day 3876provided for similar carbon number distributions in the produced fluids.A coal sample was also heated in a Fisher assay test at a rate of about17,100° C./day. The data from the Fischer assay test is indicated byreference numeral 3878. Slow heating rates resulted in less productionof components having carbon numbers greater than 20 as compared to theFischer assay results 3878. Lower heating rates also produced higherweight percentages of components with carbon numbers less than 20. Thelower heating rates produced large amounts of components having carbonnumbers near 12. A peak in carbon number distribution near 12 is typicalof the in situ conversion process for coal and oil shale.

[0908] An experiment was conducted on the coal containing formationtreated according to the in situ conversion process to measure theuniform permeability of the formation after pyrolysis. After heating aportion of the coal containing formation, a ten minute pulse of CO₂ wasinjected into the formation at first production well 3806 a and producedat well 3804 a, as shown in FIG. 137. The CO₂ tracer test was repeatedfrom production well 3806 a to well 3804 b and from production well 3806a to well 3804 c. As described above, each of the three different heatsources were located equidistant from the production well. The CO₂ wasinjected at a rate of 4.08 m³/hr (144 standard cubic feet per hour). Asillustrated in FIG. 147, the CO₂ reached each of the three differentheat sources at approximately the same time. Line 3900 illustratesproduction of CO₂ at heat source 3804 a, line 3902 illustratesproduction of CO₂ at heat source 3804 b, and line 3904 illustratesproduction of CO₂ at heat source 3804 c. As shown in FIG. 149, yield ofCO₂ from each of the three different wells was also approximately equalover time. Such approximately equivalent transfer of a tracer pulse ofCO₂ through the formation and yield of CO₂ from the formation indicatedthat the formation was substantially uniformly permeable. The fact thatthe first CO₂ arrival only occurs approximately 18 minutes after startof the CO₂ pulse indicates that no preferential paths had been createdbetween well 3806 a and 3804 a, 3804 b, and 3804 c.

[0909] The in situ permeability was measured by injecting a gas betweendifferent wells after the pyrolysis and synthesis gas formation stageswere complete. The measured permeability varied from about 4.5 darcy to39 darcy (with an average of about 20 darcy), thereby indicating thatthe permeability was high and relatively uniform. The before-treatmentpermeability was only about 50 millidarcy.

[0910] Synthesis gas was also produced in an in situ experiment from theportion of the coal containing formation shown in FIG. 136 and FIG. 137.In this experiment, heater wells were also configured to inject fluids.FIG. 148 is a plot of weight of produced volatiles (oil andnoncondensable gas) in kilograms as a function of cumulative energyinput in kilowatt hours with regard to the in situ experimental fieldtest. The figure illustrates the quantity of pyrolysis fluids andsynthesis gas produced from the formation.

[0911]FIG. 150 is a plot of the volume of oil equivalent produced (m³)as a function of energy input into the coal formation (kW·hr) from theexperimental field test. The volume of oil equivalent in cubic meterswas determined by converting the energy content of the volume ofproduced oil plus gas to a volume of oil with the same energy content.

[0912] The start of synthesis gas production, indicated by arrow 3912,was at an energy input of approximately 77,000 kW·hr. The average coaltemperature in the pyrolysis region had been raised to 620° C. Becausethe average slope of the curve in FIG. 150 in the pyrolysis region isgreater than the average slope of the curve in the synthesis gas region,FIG. 150 illustrates that the amount of useable energy contained in theproduced synthesis gas is less than that contained in the pyrolysisfluids. Therefore, synthesis gas production is less energy efficientthan pyrolysis. There are two reasons for this result. First, the two H₂molecules produced in the synthesis gas reaction have a lower energycontent than low carbon number hydrocarbons produced in pyrolysis.Second, the endothermic synthesis gas reaction consumes energy.

[0913]FIG. 151 is a plot of the total synthesis gas production (m³/min)from the coal formation versus the total water inflow (kg/h) due toinjection into the formation from the experimental field test resultsfacility. Synthesis gas may be generated in a formation at a synthesisgas generating temperature before the injection of water or steam due tothe presence of natural water inflow into hot coal formation. Naturalwater may come from below the formation.

[0914] From FIG. 151, the maximum natural water inflow is approximately5 kg/h as indicated by arrow 3920. Arrows 3922, 3924, and 3926 representinjected water rates of about 2.7 kg/h, 5.4 kg/h, and 11 kg/h,respectively, into central well 3806 a. Production of synthesis gas isat heater wells 3804 a, 3804 b, and 3804 c. FIG. 151 shows that thesynthesis gas production per unit volume of water injected decreases atarrow 3922 at approximately 2.7 kg/h of injected water or 7.7 kg/h oftotal water inflow. The reason for the decrease is that steam is flowingtoo fast through the coal seam to allow the reactions to approachequilibrium conditions.

[0915]FIG. 152 illustrates production rate of synthesis gas (m³/min) asa function of steam injection rate (kg/h) in a coal formation. Data 3930for a first run corresponds to injection at producer well 3806 a in FIG.137, and production of synthesis gas at heater wells 3804 a, 3804 b, and3804 c. Data 3932 for a second run corresponds to injection of steam atheater well 3804 c, and production of additional gas at a productionwell 3806 a. Data 3930 for the first run corresponds to the data shownin FIG. 151. As shown in FIG. 152, the injected water is in reactionequilibrium with the formation to about 2.7 kg/hr of injected water. Thesecond run results in substantially the same amount of additionalsynthesis gas produced, shown by data 3932, as the first run to about1.2 kg/hr of injected steam. At about 1.2 kg/hr, data 3930 starts todeviate from equilibrium conditions because the residence time isinsufficient for the additional water to react with the coal. Astemperature is increased, a greater amount of additional synthesis gasis produced for a given injected water rate. The reason is that athigher temperatures the reaction rate and conversion of water intosynthesis gas increases.

[0916]FIG. 153 is a plot that illustrates the effect of methaneinjection into a heated coal formation in the experimental field test(all of the units in FIGS. 153-156 are in m³ per hour). FIG. 153demonstrates hydrocarbons added to the synthesis gas producing fluid arecracked within the formation. FIG. 137 illustrates the layout of theheater and production wells at the field test facility. Methane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c. The average temperaturesmeasured at various wells were as follows: 3804 a (746° C.), 3804 b(746° C.), 3804 c (767° C.), 3808 a (592° C.), 3808 b (573° C.), 3808 c(606° C.), and 3806 a (769° C.). When the methane contacted theformation, it cracked within the formation to produce H₂ and coke. FIG.153 shows that as the methane injection rate increased, the productionof H₂ 3940 increased. This indicated that methane was cracking to formH₂. Methane production 3942 also increased which indicates that not allof the injected methane is cracked. The measured compositions of ethane,ethene, propane, and butane were negligible.

[0917]FIG. 154 is a plot that illustrates the effect of ethane injectioninto a heated coal formation in the experimental field test. Ethane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c. The average temperaturesmeasured at various wells were as follows: 3804 a (742° C.), 3804 b(750° C.), 3804 c (744° C.), 3808 a (611° C.), 3808 b (595° C.), 3808 c(626° C.), and 3806 a (818° C.). When ethane contacted the formation, itcracked to produce H₂, methane, ethene, and coke. FIG. 154 shows that asthe ethane injection rate increased, the production of H₂ 3950, methane3952, ethane 3954, and ethene 3956 increased. This indicates that ethaneis cracking to form H₂ and low molecular weight hydrocarbons. Theproduction rate of higher carbon number products (i.e., propane andpropylene) were unaffected by the injection of ethane.

[0918]FIG. 155 is a plot that illustrates the effect of propaneinjection into a heated coal formation in the experimental field test.Propane was injected into production wells 3806 a and 3806 b and fluidwas produced from heater wells 3804 a, 3804 b, and 3804 c. The averagetemperatures measured at various wells were as follows: 3804 a (737°C.), 3804 b (753° C.), 3804 c (726° C.), 3808 a (589° C.), 3808 b (573°C.), 3808 c (606° C.), and 3806 a (769° C.). When propane contacted theformation, it cracked to produce H₂, methane, ethane, ethene, propyleneand coke. FIG. 155 shows that as the propane injection rate increased,the production of H₂ 3960, methane 3962, ethane 3964, ethene 3966,propane 3968, and propylene 3969 increased. This indicates that propaneis cracking to form H₂ and lower molecular weight components.

[0919]FIG. 156 is a plot that illustrates the effect of butane injectioninto a heated coal formation in the experimental field test. Butane wasinjected into production wells 3806 a and 3806 b and fluid was producedfrom heater wells 3804 a, 3804 b, and 3804 c. The average temperaturemeasured at various wells were as follows: 3804 a (772° C.), 3804 b(764° C.), 3804 c (753° C.), 3808 a (650° C.), 3808 b (591° C.), 3808 c(624° C.), and 3806 a (830° C.). When butane contacted the formation, itcracked to produce H₂, methane, ethane, ethene, propane, propylene, andcoke. FIG. 156 shows that as the butane injection rate increased, theproduction of H₂ 3970, methane 3972, ethane 3974, ethene 3976, propane3978, and propylene 3979 increased. This indicates that butane iscracking to form H₂ and lower molecular weight components. FIG. 157 is aplot of the composition of gas (in volume percent) produced from theheated coal formation versus time in days at the experimental fieldtest. The species compositions included 3980-methane, 3982-H₂,3984-carbon dioxide, 3986-hydrogen sulfide, and 3988-carbon monoxide.FIG. 157 shows a dramatic increase in the H₂ 3982 concentration afterabout 150 days, or when synthesis gas production began.

[0920]FIG. 158 is a plot of synthesis gas conversion versus time forsynthesis gas generation runs in the experimental field test performedon separate days. The temperature of the formation was about 600° C. Thedata demonstrates initial uncertainty in measurements in the oil/waterseparator. Synthesis gas conversion consistently approached a conversionof between about 40% and 50% after about 2 hours of synthesis gasproducing fluid injection.

[0921] Table 6 includes a composition of synthesis gas producing duringa run of the in situ coal field experiment. TABLE 6 Component Mol % Wt %Methane 12.263 12.197 Ethane 0.281 0.525 Ethene 0.184 0.320 Acetylene0.000 0.000 Propane 0.017 0.046 Propylene 0.026 0.067 Propadiene 0.0010.004 Isobutane 0.001 0.004 n-Butane 0.000 0.001 1-Butene 0.001 0.003Isobutene 0.000 0.000 cis-2-Butene 0.005 0.018 trans-2-Butene 0.0010.003 1,3-Butadiene 0.001 0.005 Isopentane 0.001 0.002 n-Pentane 0.0000.002 Pentene-1 0.000 0.000 T-2-Pentene 0.000 0.000 2-Methyl-2-Butene0.000 0.000 C-2-Pentene 0.000 0.000 Hexanes 0.081 0.433 H₂ 51.247 6.405Carbon monoxide 11.556 20.067 Carbon dioxide 17.520 47.799 Nitrogen5.782 10.041 Oxygen 0.955 1.895 Hydrogen sulfide 0.077 0.163 Total100.000 100.000

[0922] The experiment was performed in batch oxidation mode at about620° C. The presence of nitrogen and oxygen is due to contamination ofthe sample with air. The mole percent of H₂, carbon monoxide, and carbondioxide, neglecting the composition of all other species, may bedetermined for the above data. For example, mole percent of H₂, carbonmonoxide, and carbon dioxide may be increased proportionally such thatthe mole percentages of the three components equals approximately 100%.In this manner, the mole percent of H₂, carbon monoxide, and carbondioxide, neglecting the composition of all other species, were 63.8%,14.4%, and 21.8%, respectively. The methane is believed to comeprimarily from the pyrolysis region outside the triangle of heaters.These values are in substantial agreement with the results ofequilibrium calculations shown in FIG. 159.

[0923]FIG. 159 is a plot of calculated equilibrium gas dry molefractions for a coal reaction with water. Methane reactions are notincluded for FIGS. 159-160. The fractions are representative of asynthesis gas that has been produced from a hydrocarbon containingformation and has been passed through a condenser to remove water fromthe produced gas. Equilibrium gas dry mole fractions are shown in FIG.159 for H₂ 4000, carbon monoxide 4002, and carbon dioxide 4004 as afunction of temperature at a pressure of 2 bar absolute. As shown inFIG. 159, at 390° C., liquid production tends to cease, and productionof gases tends to commence. The gases produced at this temperatureinclude about 67% H₂, and about 33% carbon dioxide. Carbon monoxide ispresent in negligible quantities below about 410° C. At temperatures ofabout 500° C., however, carbon monoxide is present in the produced gasin measurable quantities. For example, at 500° C., about 66.5% H₂, about32% carbon dioxide, and about 2.5% carbon monoxide are present. At 700°C., the produced gas includes about 57.5% H₂, about 15.5% carbondioxide, and about 27% carbon monoxide.

[0924]FIG. 160 is a plot of calculated equilibrium wet mole fractionsfor a coal reaction with water. Equilibrium wet mole fractions are shownfor water 4006, H₂ 4008, carbon monoxide 4010, and carbon dioxide 4012as a function of temperature at a pressure of 2 bar absolute. At 390°C., the produced gas includes about 89% water, about 7% H₂, and about 4% carbon dioxide. At 500° C., the produced gas includes about 66% water,about 22% H₂, about 11% carbon dioxide, and about 1% carbon monoxide. At700° C., the produced gas include about percent 18% water, about 47.5%H₂, about 12% carbon dioxide, and about 22.5% carbon monoxide.

[0925]FIG. 159 and FIG. 160 illustrate that at the lower end of thetemperature range at which synthesis gas may be produced (i.e., about400° C.) equilibrium gas phase fractions may not favor production of H₂within a formation. As temperature increases, the equilibrium gas phasefractions increasingly favor the production of H₂. For example, as shownin FIG. 160, the gas phase equilibrium wet mole fraction of H₂ increasesfrom about 9% at 400° C. to about 39% at 610° C. and reaches 50% atabout 800° C. FIG. 159 and FIG. 160 further illustrate that attemperatures greater than about 660° C., equilibrium gas phase fractionstend to favor production of carbon monoxide over carbon dioxide.

[0926]FIG. 159 and FIG. 160 illustrate that as the temperature increasesfrom between about 400° C. to about 1000° C., the H₂ to carbon monoxideratio of produced synthesis gas may continuously decrease throughoutthis range. For example, as shown in FIG. 160, the equilibrium gas phaseH₂ to carbon monoxide ratio at 500° C., 660° C., and 1000° C. is about22:1, about 3:1, and about 1:1, respectively. FIG. 160 also indicatesthat produced synthesis gas at lower temperatures may have a largerquantity of water and carbon dioxide than at higher temperatures. As thetemperature increases, the overall percentage of carbon monoxide andhydrogen within the synthesis gas may increase.

[0927]FIG. 161 is a flowchart of an example of a pyrolysis stage 4020and synthesis gas production stage 4022 with heat and mass balances inhigh volatile type A or B bituminous coal. In the pyrolysis stage 4020,heat 4024 is supplied to the coal formation 4026. Liquid and gasproducts 4028 and water 4030 exit the formation 4026. The portion of theformation subjected to pyrolysis is composed substantially of char afterundergoing pyrolysis heating. Char refers to a solid carbonaceousresidue that results from pyrolysis of organic material. In thesynthesis gas production stage 4022, steam 4032 and heat 4034 aresupplied to formation 4036 that has undergone pyrolysis and synthesisgas 4038 is produced.

[0928] In the embodiments in FIGS. 162-164 the methane reactions inEquations (4) and (5) are included. The calculations set forth hereinassume that char is only made of carbon and that there is an excess ofcarbon to steam. About 890 MWe of energy 4024 is required to pyrolyzeabout 105,800 metric tons per day of coal. The pyrolysis products 4028include liquids and gases with a production of 23,000 cubic meters perday. The pyrolysis process also produces about 7,160 metric tons per dayof water 4030. In the synthesis gas stage about 57,800 metric tons perday of char with injection of 23,000 metric tons per day of steam 4032and 2,000 MWe of energy 4034 with a 20% conversion will produce 12,700cubic meters equivalent oil per day of synthesis gas 4038.

[0929]FIG. 162 is an example of a low temperature in situ synthesis gasproduction that occurs at a temperature of about 450° C. with heat andmass balances in a hydrocarbon containing formation that was previouslypyrolyzed. A total of about 42,900 metric tons per day of water isinjected into formation 4100 which may be char. FIG. 162 illustratesthat a portion of water 4102 at 25° C. is injected directly into theformation 4100. A portion of water 4102 is converted into steam 4104 ata temperature of about 130° C. and a pressure at about 3 bar absoluteusing about 1227 MWe of energy 4106 and injected into formation 4100. Aportion of the remaining steam may be converted into steam 4108 at atemperature of about 450° C. and a pressure at about 3 bar absoluteusing about 318 MWe of energy 4110. The synthesis gas productioninvolves about 23% conversion of 13,137 metric tons per day of char toproduce 56.6 millions of cubic meters per day of synthesis gas with anenergy content of 5,230 MW. About 238 MW of energy 4112 is supplied toformation 4100 to account for the endothermic heat of reaction of thesynthesis gas reaction. The product stream 4114 of the synthesis gasreaction includes 29,470 metric tons per day of water at 46 volumepercent, 501 metric tons per day carbon monoxide at 0.7 volume percent,540 tons per day H₂ at 10.7 volume percent, 26,455 metric tons per daycarbon dioxide at 23.8 volume percent, and 7,610 metric tons per daymethane at 18.8 volume percent.

[0930]FIG. 163 is an example of a high temperature in situ synthesis gasproduction that occurs at a temperature of about 650° C. with heat andmass balances in a hydrocarbon containing formation that was previouslypyrolyzed. A total of about 34,352 metric tons per day of water isinjected into formation 4200. FIG. 163 illustrates that a portion ofwater 4202 at 25° C. is injected directly into formation 4200. A portionof water 4202 is converted into steam 4204 at a temperature of about130° C. and a pressure at about 3 bar absolute using about 982 MWe ofenergy 4206, and injected into formation 4200. A portion of theremaining steam is converted into steam 4208 at a temperature of about650° C. and a pressure at about 3 bar absolute using about 413 MWe ofenergy 4210. The synthesis gas production involves about 22% conversionof 12,771 metric tons per day of char to produce 56.6 millions of cubicmeters per day of synthesis gas with an energy content of 5,699 MW.About 898 MW of energy 4212 is supplied to formation 4200 to account forthe endothermic heat of reaction of the synthesis gas reaction. Theproduct stream 4214 of the synthesis gas reaction includes 10,413 metrictons per day of water at 22.8 volume percent, 9,988 metric tons per daycarbon monoxide at 14.1 volume percent, 1771 metric tons per day H₂ at35 volume percent, 21,410 metric tons per day carbon dioxide at 19.3volume percent, and 3535 metric tons per day methane at 8.7 volumepercent.

[0931]FIG. 164 is an example of an in situ synthesis gas production in ahydrocarbon containing formation with heat and mass balances. Synthesisgas generating fluid that includes water 4302 is supplied to theformation 4300. A total of about 22,000 metric tons per day of water isrequired for a low temperature process and about 24,000 metric tons perday is required for a high temperature process. A portion of the watermay be introduced into the formation as steam. Steam 4304 is produced bysupplying heat to the water from an external source. About 7,119 metrictons per day of steam is provided for the low temperature process andabout 6913 metric tons per day of steam is provided for the hightemperature process.

[0932] At least a portion of the aqueous fluid 4306 exiting formation4300 is recycled 4308 back into the formation for generation ofsynthesis gas. For a low temperature process about 21,000 metric tonsper day of aqueous fluids is recycled and for a high temperature processabout 10,000 metric tons per day of aqueous fluids is recycled. Theproduced synthesis gas 4310 includes carbon monoxide, H₂, and methane.The produced synthesis gas has a heat content of about 430,000 MMBtu perday for a low temperature process and a heat content of about 470,000MMBtu per day for a low temperature process. Carbon dioxide 4312produced in the synthesis gas process includes about 26,500 metric tonsper day in the low temperature process and about 21,500 metric tons perday in the high temperature process. At least a portion of the producedsynthesis gas 4310 is used for combustion to heat the formation. Thereis about 7,119 metric tons per day of carbon dioxide in the steam 4308for the low temperature process and about 6,913 metric tons per day ofcarbon dioxide in the steam for the high temperature process. There isabout 2,551 metric tons per day of carbon dioxide in a heat reservoirfor the low temperature process and about 9,628 metric tons per day ofcarbon dioxide in a heat reservoir for the high temperature process.There is about 14,571 metric tons per day of carbon dioxide in thecombustion of synthesis gas for the low temperature process and about18,503 metric tons per day of carbon dioxide in produced combustionsynthesis gas for the high temperature process. The produced carbondioxide has a heat content of about 60 gigajoules (“GJ”) per metric tonfor the low temperature process and about 6.3 GJ per metric ton for thehigh temperature process.

[0933] Table 7 is an overview of the potential production volume ofapplications of synthesis gas produced by wet oxidation. The estimatesare based on 56.6 million standard cubic meters of synthesis gasproduced per day at 700° C. TABLE 7 Production (main Applicationproduct) Power 2,720 Megawatts Hydrogen 2,700 metric tons/day NH₃ 13,800metric tons/day CH₄ 7,600 metric tons/day Methanol 13,300 metrictons/day Shell Middle 5,300 metric tons/day Distillates

[0934] Experimental adsorption data has demonstrated that carbon dioxidemay be stored in coal that has been pyrolyzed. FIG. 165 is a plot of thecumulative adsorbed methane and carbon dioxide in cubic meters permetric ton versus pressure in bar absolute at 25° C. on coal. The coalsample is sub-bituminous coal from Gillette, Wyo. Data sets 4401, 4402,4403, 4404, and 4405 are for carbon dioxide adsorption on a posttreatment coal sample that has been pyrolyzed and has undergonesynthesis gas generation. Data set 4406 is for adsorption on anunpyrolyzed coal sample from the same formation. Data set 4401 isadsorption of methane at 25° C. Data sets 4402, 4403, 4404, and 4405 areadsorption of carbon dioxide at 25° C., 50° C., 100° C., and 150° C.,respectively. Data set 4406 is adsorption of carbon dioxide at 25° C. onthe unpyrolyzed coal sample. FIG. 165 shows that carbon dioxide attemperatures between 25° C. and 100° C. is more strongly adsorbed thanmethane at 25° C. in the pyrolyzed coal. FIG. 165 demonstrates that acarbon dioxide stream passed through post treatment coal tends todisplace methane from the post treatment coal.

[0935] Computer simulations have demonstrated that carbon dioxide may besequestered in both a deep coal formation and a post treatment coalformation. The Comet2 Simulator determined the amount of carbon dioxidethat could be sequestered in a San Juan Basin type deep coal formationand a post treatment coal formation. The simulator also determined theamount of methane produced from the San Juan Basin type deep coalformation due to carbon dioxide injection. The model employed for boththe deep coal formation and the post treatment coal formation was a 1.3km² area, with a repeating 5 spot well pattern. The 5 spot well patternincluded four injection wells arranged in a square and one productionwell at the center of the square. The properties of the San Juan Basinand the post treatment coal formations are shown in Table 8. Additionaldetails of simulations of carbon dioxide sequestration in deep coalformations and comparisons with field test results may be found in PilotTest Demonstrates How Carbon Dioxide Enhances Coal Bed Methane Recovery,Lanny Schoeling and Michael McGovern, Petroleum Technology Digest, Sept.2000, p. 14-15. TABLE 8 Post treatment coal Deep Coal Formation (Sanformation (Post pyrolysis Juan Basin) process) Coal Thickness (m) 9 9Coal Depth (m) 990 460 Initial Pressure (bars abs.) 114 2 InitialTemperature 25° C. 25° C. Permeability (md) 5.5 (horiz.), 0 (vertical)10,000 (horiz.), 0 (vertical) Cleat porosity 0.2% 40%

[0936] The simulation model accounts for the matrix and dual porositynature of coal and post treatment coal. For example, coal and posttreatment coal are composed of matrix blocks. The spaces between theblocks are called “cleats”. Cleat porosity is a measure of availablespace for flow of fluids in the formation. The relative permeabilitiesof gases and water within the cleats required for the simulation werederived from field data from the San Juan coal. The same values forrelative permeabilities were used in the post treatment coal formationsimulations. Carbon dioxide and methane were assumed to have the samerelative permeability.

[0937] The cleat system of the deep coal formation was modeled asinitially saturated with water. Relative permeability data for carbondioxide and water demonstrate that high water saturation inhibitsabsorption of carbon dioxide within cleats. Therefore, water is removedfrom the formation before injecting carbon dioxide into the formation.

[0938] In addition, the gases within the cleats may adsorb in the coalmatrix. The matrix porosity is a measure of the space available forfluids to adsorb in the matrix. The matrix porosity and surface areawere taken into account with experimental mass transfer and isothermadsorption data for coal and post treatment coal. Therefore, it is notnecessary to specify a value of the matrix porosity and surface area inthe model.

[0939] The preferential adsorption of carbon dioxide over methane onpost treatment coal was incorporated into the model based onexperimental adsorption data. For example, FIG. 165 demonstrates thatcarbon dioxide has a significantly higher cumulative adsorption thanmethane over an entire range of pressures at a specified temperature.Once the carbon dioxide enters in the cleat system, methane diffuses outof and desorbs off the matrix. Similarly, carbon dioxide diffuses intoand adsorbs onto the matrix. In addition, FIG. 165 also shows carbondioxide may have a higher cumulative adsorption on a pyrolyzed coalsample than an unpyrolyzed coal.

[0940] The pressure-volume-temperature (PVT) properties and viscosityrequired for the model were taken from literature data for the purecomponent gases.

[0941] The simulation modeled a sequestration process over a time periodof about 3700 days for the deep coal formation model. Removal of thewater in the coal formation was simulated by production from all fivewells. The production rate of water was about 40 m³/day for about thefirst 370 days. The production rate of water decreased significantlyafter the first 370 days. It continued to decrease through the remainderof the simulation run to about zero at the end. Carbon dioxide injectionwas started at approximately 370 days at a flow rate of about 113,000standard (in this context “standard” means 1 atmosphere pressure and15.5 degrees Celsius) m³/day. The injection rate of carbon dioxide wasdoubled to about 226,000 standard m³/day at approximately 1440 days. Theinjection rate remained at about 226,000 standard m³/day until the endof the simulation run.

[0942]FIG. 177 illustrates the pressure at the wellhead of the injectionwells as a function of time during the simulation. The pressuredecreased from 114 bars absolute to about 20 bars absolute over thefirst 370 days. The decrease in the pressure was due to removal of waterfrom the coal formation. Pressure then started to increase substantiallyas carbon dioxide injection started at 370 days. The pressure reached amaximum of 98 bars. The pressure then began to gradually decrease after480 days. At about 1440 days, the pressure increased again to about 143bars absolute due to the increase in the carbon dioxide injection rate.The pressure gradually increased until about 3640 days. The pressurejumped at about 3640 days because the production well was closed off.

[0943]FIG. 178 illustrates the production rate of carbon dioxide 5060and methane 5070 as a function of time in the simulation. FIG. 178 showsthat carbon dioxide was produced at a rate between about 0-10,000 m³/dayduring approximately the first 2400 days. The production rate of carbondioxide was significantly below the injection rate. Therefore, thesimulation predicts that most of the injected carbon dioxide is beingsequestered in the coal formation. However, at about 2400 days, theproduction rate of carbon dioxide started to rise significantly due toonset of saturation of the coal formation.

[0944] In addition, FIG. 178 shows that methane was desorbing as carbondioxide was adsorbing in the coal formation. Between about 370-2400days, the methane production rate 5070 increased from about 60,000 toabout 115,000 standard m³/day. The increase in the methane productionrate between about 1440-2400 days was caused by the increase in carbondioxide injection rate at about 1440 days. The production rate ofmethane started to decrease after about 2400 days. This was due to thesaturation of the coal formation. The simulation predicted a 50%breakthrough at about 2700 days. “Breakthrough” is defined as the ratioof the flow rate of carbon dioxide to the total flow rate of the totalproduced gas times 100%. Also, the simulation predicted about a 90%breakthrough at about 3600 days.

[0945]FIG. 179 illustrates cumulative methane produced 5090 and thecumulative net carbon dioxide injected 5080 as a function of time duringthe simulation. The cumulative net carbon dioxide injected is the totalcarbon dioxide produced subtracted from the total carbon dioxideinjected. FIG. 179 shows that by the end of the simulated injectionabout twice as much carbon dioxide was stored than methane produced. Inaddition, the methane production was about 0.24 billion standard m³ at50% carbon dioxide breakthrough. Also, the carbon dioxide sequestrationwas about 0.39 billion standard m³ at 50% carbon dioxide breakthrough.The methane production was about 0.26 billion standard m³ at 90% carbondioxide breakthrough. Also, the carbon dioxide sequestration was about0.46 billion standard m³ at 90% carbon dioxide breakthrough.

[0946] Table 8 shows that the permeability and porosity of thesimulation in the post treatment coal formation were both significantlyhigher than in the deep coal formation prior to treatment. Also, theinitial pressure was much lower. The depth of the post treatment coalformation was shallower than the deep coal bed methane formation. Thesame relative permeability data and PVT data used for the deep coalformation were used for the coal formation simulation. The initial watersaturation for the post treatment coal formation was set at 70%. Waterwas present because it is used to cool the hot spent coal formation to25° C. The amount of methane initially stored in the post treatment coalis very low.

[0947] The simulation modeled a sequestration process over a time periodof about 3800 days for the post treatment coal formation model. Thesimulation modeled removal of water from the post treatment coalformation with production from all five wells. During about the first200 days, the production rate of water was about 680,000 standardm³/day. From about 200-3300 days the water production rate was betweenabout 210,000 to about 480,000 standard m³/day. Production rate of waterwas negligible after about 3300 days. Carbon dioxide injection wasstarted at approximately 370 days at a flow rate of about 113,000standard m³/day. The injection rate of carbon dioxide was increased toabout 226,000 standard m³/day at approximately 1440 days. The injectionrate remained at 226,000 standard m³/day until the end of the simulatedinjection.

[0948]FIG. 180 illustrates the pressure at the wellhead of the injectionwells as a function of time during the simulation of the post treatmentcoal formation model. The pressure was relatively constant up to about370 days. The pressure increased through most of the rest of thesimulation run up to about 36 bars absolute. The pressure rose steeplystarting at about 3300 days because the production well was closed off.

[0949]FIG. 181 illustrates the production rate of carbon dioxide as afunction of time in the simulation of the post treatment coal formationmodel. FIG. 181 shows that the production rate of carbon dioxide wasalmost negligible during approximately the first 2200 days. Therefore,the simulation predicts that nearly all of the injected carbon dioxideis being sequestered in the post treatment coal formation. However, atabout 2240 days, the produced carbon dioxide began to increase. Theproduction rate of carbon dioxide started to rise significantly due toonset of saturation of the post treatment coal formation.

[0950]FIG. 182 illustrates cumulative net carbon dioxide injected as afunction of time during the simulation in the post treatment coalformation model. The cumulative net carbon dioxide injected is the totalcarbon dioxide produced subtracted from the total carbon dioxideinjected. FIG. 182 shows that the simulation predicts a potential netsequestration of carbon dioxide of 0.56 Bm . This value is greater thanthe value of 0.46 Bm³ at 90% carbon dioxide breakthrough in the deepcoal formation. However, comparison of FIG. 177 with FIG. 180 shows thatsequestration occurs at much lower pressures in the post treatment coalformation model. Therefore, less compression energy was required forsequestration in the post treatment coal formation.

[0951] The simulations show that large amounts of carbon dioxide may besequestered in both deep coal formations and in post treatment coalformations that have been cooled. Carbon dioxide may be sequestered inthe post treatment coal formation, in coal formations that have not beenpyrolyzed, and/or in both types of formations.

[0952]FIG. 166 is a flowchart of an embodiment of an in situ synthesisgas production process integrated with a SMDS Fischer-Tropsch and waxcracking process with heat and mass balances. The synthesis gasgenerating fluid injected into the formation includes about 24,000metric tons per day of water 4530, which includes about 5,500 metrictons per day of water 4540 recycled from the SMDS Fischer-Tropsch andwax cracking process 4520. A total of about 1700 MW of energy issupplied to the in situ synthesis gas production process. About 1020 MWof energy 4535 of the approximately 1700 MW of energy is supplied by insitu reaction of an oxidizing fluid with the formation, andapproximately 680 MW of energy 4550 is supplied by the SMDSFischer-Tropsch and wax cracking process 4520 in the form of steam.About 12,700 cubic meters equivalent oil per day of synthesis gas 4560is used as feed gas to the SMDS Fischer-Tropsch and wax cracking process4520. The SMDS Fischer-Tropsch and wax cracking process 4520 producesabout 4,770 cubic meters per day of products 4570 that may includenaphtha, kerosene, diesel, and about 5,880 cubic meters equivalent oilper day of off gas 4580 for a power generation facility.

[0953]FIG. 167 is a comparison between numerical simulation and the insitu experimental coal field test composition of synthesis gas producedas a function of time. The plot excludes nitrogen and traces of oxygenthat were contaminants during gas sampling. Symbols representexperimental data and curves represent simulation results. Hydrocarbons4601 are methane since all other heavier hydrocarbons have decomposed atthe prevailing temperatures. The simulation results are moving averagesof raw results, which exhibit peaks and troughs of approximately ±10percent of the averaged value. In the model, the peaks of H₂ occurredwhen fluids were injected into the coal seam, and coincided with lows inCO₂ and CO.

[0954] The simulation of H₂ 4604 provides a good fit to observedfraction of H₂ 4603. The simulation of methane 4602 provides a good fitto observed fraction of methane 4601. The simulation of carbon dioxide4606 provides a good fit to observed fraction of carbon dioxide 4605.The simulation of CO 4608 overestimated the fraction of CO 4607 by 4-5percentage points. Carbon monoxide is the most difficult of thesynthesis gas components to model. Also, the carbon monoxide discrepancymay be due to fact that the pattern temperatures exceeded the 550° C.,the upper limit at which the numerical model was calibrated.

[0955] Other methods of producing synthesis gas were successfullydemonstrated at the experimental field test. These included continuousinjection of steam and air, steam and oxygen, water and air, water andoxygen, steam, air and carbon dioxide. All these injections successfullygenerated synthesis gas in the hot coke formation.

[0956] Low temperature pyrolysis experiments with tar sand wereconducted to determine a pyrolysis temperature zone and effects oftemperature in a heated portion on the quality of the producedpyrolization fluids. The tar sand was collected from the Athabasca tarsand region. FIG. 89 depicts a retort and collection system used toconduct the experiment. The retort and collection may be configured asdescribed herein.

[0957] Laboratory experiments were conducted on three tar samplescontained in their natural sand matrix. The three tar samples werecollected from the Athabasca tar sand region in western Canada. In eachcase, core material received from a well was mixed and then was split.One aliquot of the split core material was used in the retort, and thereplicate aliquot was saved for comparative analyses. Materials sampledincluded a tar sample within a sandstone matrix.

[0958] The heating rate for the runs was varied at 1° C./day, 5° C./day,and 10° C./day. The pressure condition was varied for the runs atpressures of 1 bar, 7.9 bars, and 28.6 bars. Run #78 was operated withno backpressure 1 bar absolute and a heating rate of 1° C./day. Run #79was operated with no backpressure 1 bar absolute and a heating rate of5° C./day. Run #81 was operated with no backpressure 1 bar absolute anda heating rate of 10° C./day. Run #86 was operated with at a pressure of7.9 bars absolute and a heating rate of 10° C./day. Run #96 was operatedwith at a pressure of 28.6 bars absolute and a heating rate of 10°C./day. In general, 0.5 to 1.5 kg initial weight of the sample wasrequired to fill the available retort cells.

[0959] The internal temperature for the runs was raised from ambient to110° C., 200° C., 225° C. and 270° C. with 24 hours holding time betweeneach temperature increase. Most of the moisture was removed from thesamples during this heating. Beginning at 270° C., the temperature wasincreased by 1° C./day, 5° C./day, or 10° C./day until no further fluidwas produced. The temperature was monitored and controlled during theheating of this stage.

[0960] Produced liquid was collected in graduated glass collectiontubes. Produced gas was collected in graduated glass collection bottles.Fluid volumes were read and recorded daily. Accuracy of the oil and gasvolume readings was within +/−0.6% and 2%, respectively. The experimentswere stopped when fluid production ceased. Power was turned off and morethan 12 hours was allowed for the retort to fall to room temperature.The pyrolyzed sample remains were unloaded, weighed, and stored insealed plastic cups. Fluid production and remaining rock material weresent out for analytical experimentation.

[0961] In addition, Dean Stark toluene solvent extraction was used toassay the amount of tar contained in the sample. In such an extractionprocedure, a solvent such as toluene or a toluene/xylene mixture may bemixed with a sample and may be refluxed under a condenser using areceiver. As the refluxed sample condenses, two phases of the sample mayseparate as they flow into the receiver. For example, tar may remain inthe receiver while the solvent returns to the flask. Detailed proceduresfor Dean Stark toluene solvent extraction are provided by the AmericanSociety for Testing and Materials (“ASTM”). The ASTM is incorporated byreference as if fully set forth herein. A 30 g sample from each depthwas sent for Dean Stark extraction analysis.

[0962] Table 9 illustrates the elemental analysis of initial tar and ofthe produced fluids for runs #81, #86, and #96. These data are all for aheating rate of 10° C./day. Only a pressure was varied between the runs.TABLE 9 Run P # (bar) C (wt %) H (wt %) N (wt %) O (wt %) S (wt %)Initial — 76.58 11.28 1.87 5.96 4.32 Tar 81 1 85.31 12.17 0.08 — 2.47 867.9 81.78 11.69 0.06 4.71 1.76 96 28.6 82.68 11.65 0.03 4.31 1.33

[0963] As illustrated in Table 9, pyrolysis of the tar sand decreasesnitrogen and sulfur weight percentages in a produced fluid and increasescarbon weight percentage a produced fluid. Increasing the pressure inthe pyrolysis experiment appears to further decrease the nitrogen andsulfur weight percentage in the produced fluids.

[0964] Table 10 illustrates NOISE (Nitric Oxide Ionization SpectrometryEvaluation) analysis data for runs #81, #86, and #96 and the initialtar. NOISE has been developed by a commercial laboratory as aquantitative analysis of the weight percentages of the main constituentsin oil. The remaining weight percentage (47.2%) in the initial tar maybe found in a residue. TABLE 10 Paraffins Cycloalkanes PhenolsMono-aromatics Run # P (bar) (wt %) (wt %) (wt %) (wt %) Initial — 7.0829.15 0 6.73 Tar 81 1 15.36 46.7 0.34 21.04 86 7.9 27.16 45.8 0.54 16.8896 28.6 26.45 36.56 0.47 28.0

[0965] Run # P (bar) Di-aromatics (wt %) Tri-aromatics (wt %)Tetra-aromatics (wt %) Initial Tar — 8.12 1.70 0.02 81 1 14.83 1.72 0.0186 7.9 9.09 0.53 0 96 28.6 8.52 0 0

[0966] As illustrated in Table 10, pyrolyzation of tar sand produces aproduct fluid with a significantly higher weight percentage ofparaffins, cycloalkanes, and mono-aromatics than may be found in theinitial tar sand. Increasing the pressure up to 7.9 bars absoluteappears to substantially eliminate the production of tetra-aromatics.Further increasing the pressure up to 28.6 bars absolute appears tosubstantially eliminate the production of tri-aromatics. An increase inthe pressure also appears to decrease a production of di-aromatics.Increasing the pressure up to 28.6 bars absolute also appears tosignificantly increase a production of mono-aromatics. This may be dueto an increased hydrogen partial pressure at the higher pressure. Theincreased hydrogen partial pressure may reduce poly-aromatic compoundsto the mono-aromatics.

[0967]FIG. 168 illustrates plots of weight percentages of carboncompounds versus carbon number for initial tar 4703 and runs atpressures of 1 bar absolute 4704, 7.9 bars absolute 4705, and 28.6 barsabsolute 4706 with a heating rate of 10° C./day. From the plots ofinitial tar 4703 and a pressure of 1 bar absolute 4704 it can be seenthat pyrolysis shifts an average carbon number distribution torelatively lower carbon numbers. For example, a mean carbon number inthe carbon distribution of plot 4703 is at about carbon number nineteenand a mean carbon number in the carbon distribution of plot 4704 is atabout carbon number seventeen. Increasing the pressure to 7.9 barsabsolute 4705 further shifts the average carbon number distribution toeven lower carbon numbers. Increasing the pressure to 7.9 bars absolute4705 also shifts the mean carbon number in the carbon distribution to acarbon number of about thirteen. Further increasing the pressure to 28.6bars absolute 4706 reduces the mean carbon number to about eleven.Increasing the pressure is believed to decrease the average carbonnumber distribution by increasing a hydrogen partial pressure in theproduct fluid. The increased hydrogen partial pressure in the productfluid allows hydrogenation, dearomatization, and/or pyrolysis of largemolecules to from smaller molecules. Increasing the pressure alsoincreases a quality of the produced fluid. For example, the API gravityof the fluid increased from less than about 10° for the initial tar, toabout 31° for a pressure of 1 bar absolute, to about 39° for a pressureof 7.9 bars absolute, to about 45° for a pressure of 28.6 bars absolute.

[0968]FIG. 169 illustrates bar graphs of weight percentages of carboncompounds for various pyrolysis heating rates and pressures. Bar graph4710 illustrates weight percentages for pyrolysis with a heating rate of1° C./day at a pressure of 1 bar absolute. Bar graph 4712 illustratesweight percentages for pyrolysis with a heating rate of 5° C./day at apressure of 1 bar. Bar graph 4714 illustrates weight percentages forpyrolysis with a heating rate of 10° C./day at a pressure of 1 bar. Bargraph 4716 illustrates weight percentages for pyrolysis with a heatingrate of 10° C./day at a pressure of 7.9 bars absolute. Weightpercentages of paraffins 4720, cycloalkanes 4722, mono-aromatics 4724,di-aromatics 4726, and tri-aromatics 4728 are illustrated in the bargraphs. The bar graphs demonstrate that a variation in the heating ratebetween 1° C./day to 10° C./day does not significantly affect thecomposition of the product fluid. Increasing the pressure from 1 barabsolute to 7.9 bars absolute, however, affects a composition of theproduct fluid. Such an effect may be characteristic of the effectsdescribed in FIG. 168 and Tables 9 and 10 above.

[0969] A three-dimensional (3-D) simulation model was used to simulatean in situ conversion process for a tar sand containing formation. Aheat injection rate was calculated using a separate numerical code(CFX). The heat injection rate was calculated at 500 watts per foot(1640 watts per meter). The 3-D simulation was based on adilation-recompaction model for tar sands. A target zone thickness of 50meters was used. Input data for the simulation were as follows:

[0970] Depth of target zone=280 meters;

[0971] Thickness=50 meters;

[0972] Porosity=0.27;

[0973] Oil saturation=0.84;

[0974] Water saturation=0.16;

[0975] Permeability=1000 millidarcy;

[0976] Vertical permeability versus horizontal permeability=0.1;

[0977] Overburden=shale; and

[0978] Base rock=wet carbonate.

[0979] Six component fluids were used based on fluids found in Athabascatar sands. The six component fluids were: heavy fluid; light fluid; gas;water; pre-char; and char. The spacing between wells was set at 9.1meters on a triangular pattern. Eleven horizontal heaters with a 300 mheater length were used with heat outputs set at the previouslycalculated value of 1640 watts per meter.

[0980]FIG. 170 illustrates a plot of oil production (in cubic meters)versus time (in days) for various bottomhole pressures at a producerwell. Plot 4742 illustrates oil production for a pressure of 1.03 barsabsolute. Plot 4740 illustrates oil production for a pressure of 6.9bars absolute. FIG. 170 demonstrates that increasing the bottomholepressure will decrease oil production in a tar sand formation.

[0981]FIG. 171 illustrates a plot of a ratio of heat content of producedfluids from a reservoir against heat input to heat the reservoir versustime (in days). Plot 4752 illustrates the ratio versus time for heatingan entire reservoir to a pyrolysis temperature. Plot 4752 illustratesthe ratio versus time for allowing partial drainage in the reservoirinto selected pyrolyzation section 4750. FIG. 171 demonstrates thatallowing partial drainage in the reservoir tends to increase the heatcontent of produced fluids versus heating the entire reservoir, for agiven heat input into the reservoir.

[0982]FIG. 172 illustrates a plot of weight percentage versus carbonnumber distribution for the simulation. Plot 4760 illustrates the carbonnumber distribution for the initial tar sand. The initial tar sand hasan API gravity of 6°. Plot 4762 illustrates the carbon numberdistribution for in situ conversion of the tar sand up to a temperatureof 350° C. Plot 4762 has an API gravity of 30°. From FIG. 172, it can beseen that the in situ conversion process substantially increases thequality of oil found in the tar sands, as evidenced by the increased APIgravity and the carbon number distribution shift to lower carbonnumbers. The lower carbon number distribution was also evidenced by theresult showing that a majority of the produced fluid was produced as avapor.

[0983]FIG. 102 illustrates a tar sand drum experimental apparatus usedto conduct an experiment. Drum 3400 was filled with Athabasca tar sandand heated. All experiments were conducted using the system shown inFIG. 102 (see other description herein). Vapors were produced from thedrum, cooled, separated into liquids and gases, and then analyzed. Twoseparate experiments were conducted, each using tar sand from the samebatch, but the drum pressure was maintained at 1 bar absolute in oneexperiment (the low pressure experiment), and the drum pressure wasmaintained at 6.9 bars absolute in the other experiment (the highpressure experiment). The drum pressures were allowed to autogenouslyincrease to the maintained pressure as temperatures were increased.

[0984]FIG. 173 illustrates mole % of hydrogen in the gases during theexperiment (i.e., when the drum temperature was increased at the rate of2 degrees Celsius per day). Line 4770 illustrates results obtained whenthe drum pressure was maintained at 1 bar absolute. Line 4772illustrates results obtained when the drum pressure was maintained at6.9 bars absolute. FIG. 173 demonstrates that a higher mole percent ofhydrogen was produced in the gas when the drum was maintained at lowerpressures. It is believed that increasing the drum pressure drovehydrogen into the liquids in the drum. The hydrogen will tend tohydrogenate heavy hydrocarbons.

[0985]FIG. 174 illustrates API gravity of liquids produced from the drumas temperature was increased in the drum. Line 4782 depicts results fromthe high pressure experiment and line 4780 depicts results from the lowpressure experiment. As illustrated in FIG. 174, higher quality liquidswere produced at the higher drum pressure. It is believed that higherquality liquids were produced because more hydrogenation occurred in thedrum during the high pressure experiment (although the hydrogenconcentration in the gas was less in the high pressure experiment, thedrum pressures were significantly greater, and therefore the partialpressure of hydrogen in the drum was greater in the high pressureexperiment).

[0986] Further modifications and alternative embodiments of variousaspects of the invention may be apparent to those skilled in the art inview of this description. Accordingly, this description is to beconstrued as illustrative only and is for the purpose of teaching thoseskilled in the art the general manner of carrying out the invention. Itis to be understood that the forms of the invention shown and describedherein are to be taken as the presently preferred embodiments. Elementsand materials may be substituted for those illustrated and describedherein, parts and processes may be reversed, and certain features of theinvention may be utilized independently, all as would be apparent to oneskilled in the art after having the benefit of this description of theinvention. Changes may be made in the elements described herein withoutdeparting from the spirit and scope of the invention as described in thefollowing claims.

What is claimed is:
 1. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least one portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; controlling the heat from the one or more heat sources suchthat an average temperature within at least a majority of the selectedsection of the formation is less than about 375° C.; and producing amixture from the formation.
 2. The method of claim 1, wherein the one ormore heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation. 3.The method of claim 1, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 4. The method of claim 1, wherein the oneor more heat sources comprise electrical heaters.
 5. The method of claim1, wherein the one or more heat sources comprise surface burners.
 6. Themethod of claim 1, wherein the one or more heat sources compriseflameless distributed combustors.
 7. The method of claim 1, wherein theone or more heat sources comprise natural distributed combustors.
 8. Themethod of claim 1, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.9. The method of claim 1, further comprising controlling a pressurewithin at least a majority of the selected section of the formation witha valve coupled to at least one of the one or more heat sources.
 10. Themethod of claim 1, further comprising controlling a pressure within atleast a majority of the selected section of the formation with a valvecoupled to a production well located in the formation.
 11. The method ofclaim 1, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 12. The method of claim 1, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 13. The methodof claim 1, wherein allowing the heat to transfer from the one or moreheat sources to the selected section comprises transferring heatsubstantially by conduction.
 14. The method of claim 1, whereinproviding heat from the one or more heat sources comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 15. Themethod of claim 1, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about
 250. 16. The methodof claim 1, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 17. The method of claim 1,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 18. The method ofclaim 1, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe non-condensable hydrocarbons are olefins.
 19. The method of claim 1,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 20. The method ofclaim 1, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 21. Themethod of claim 1, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 22. The methodof claim 1, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 23. Themethod of claim 1, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 24. The method of claim1, wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 25. The methodof claim 1, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 26. The method of claim 1,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 27. The method of claim 1, wherein theproduced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, and wherein the hydrogenis greater than about 10% by volume of the non-condensable component andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 28. The method of claim 1, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 29. The method of claim 1,wherein the produced mixture comprises ammonia, and wherein the ammoniais used to produce fertilizer.
 30. The method of claim 1, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bar absolute.
 31. The method of claim 1, furthercomprising controlling formation conditions such that the producedmixture comprises a partial pressure of H₂ within the mixture greaterthan about 0.5 bar.
 32. The method of claim 31, wherein the partialpressure of H₂ is measured when the mixture is at a production well. 33.The method of claim 1, wherein controlling formation conditionscomprises recirculating a portion of hydrogen from the mixture into theformation.
 34. The method of claim 1, further comprising altering apressure within the formation to inhibit production of hydrocarbons fromthe formation having carbon numbers greater than about
 25. 35. Themethod of claim 1, further comprising: providing hydrogen (H₂) to theheated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 36. Themethod of claim 1, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 37. The method of claim 1, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 38. Themethod of claim 1, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 39. The method of claim 1, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 40. Themethod of claim 1, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 41. The methodof claim 1, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern. 42.The method of claim 1, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 43. The methodof claim 1 further comprising separating the produced mixture into a gasstream and a liquid stream.
 44. The method of claim 1, furthercomprising separating the produced mixture into a gas stream and aliquid stream and separating the liquid stream into an aqueous streamand a non-aqueous stream.
 45. The method of claim 1, wherein theproduced mixture comprises H₂S, the method further comprising separatinga portion of the H₂S from non-condensable hydrocarbons.
 46. The methodof claim 1, wherein the produced mixture comprises CO₂, the methodfurther comprising separating a portion of the CO₂ from non-condensablehydrocarbons.
 47. The method of claim 1, wherein the mixture is producedfrom a production well, wherein the heating is controlled such that themixture can be produced from the formation as a vapor.
 48. The method ofclaim 1, wherein the mixture is produced from a production well, themethod further comprising heating a wellbore of the production well toinhibit condensation of the mixture within the wellbore.
 49. The methodof claim 1, wherein the mixture is produced from a production well,wherein a wellbore of the production well comprises a heater elementconfigured to heat the formation adjacent to the wellbore, and furthercomprising heating the formation with the heater element to produce themixture, wherein the mixture comprises a large non-condensablehydrocarbon gas component and H₂.
 50. The method of claim 1, wherein theminimum pyrolysis temperature is about 270° C.
 51. The method of claim1, further comprising maintaining the pressure within the formationabove about 2.0 bar absolute to inhibit production of fluids havingcarbon numbers above
 25. 52. The method of claim 1, further comprisingcontrolling pressure within the formation in a range from aboutatmospheric pressure to about 100 bar, as measured at a wellhead of aproduction well, to control an amount of condensable hydrocarbons withinthe produced mixture, wherein the pressure is reduced to increaseproduction of condensable hydrocarbons and wherein the pressure isincreased to increase production of non-condensable hydrocarbons. 53.The method of claim 1, further comprising controlling pressure withinthe formation in a range from about atmospheric pressure to about 100bar, as measured at a wellhead of a production well, to control an APIgravity of condensable hydrocarbons within the produced mixture, whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 54. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; allowing the heat to transfer from at least the portionto a selected section of the formation substantially by conduction ofheat; pyrolyzing at least some hydrocarbons within the selected sectionof the formation; and producing a mixture from the formation.
 55. Themethod of claim 54, wherein the one or more heat sources comprise atleast two heat sources. and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 56. The method of claim 54, whereinthe one or more heat sources comprise electrical heaters.
 57. The methodof claim 54, wherein the one or more heat sources comprise surfaceburners.
 58. The method of claim 54, wherein the one or more heatsources comprise flameless distributed combustors.
 59. The method ofclaim 54, wherein the one or more heat sources comprise naturaldistributed combustors.
 60. The method of claim 54, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 61. The method of claim 54,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1.0° C. per day duringpyrolysis.
 62. The method of claim 54, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heat sources, wherein the formation has an averageheat capacity (C_(v)). and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 63. The method of claim 54, whereinproviding heat from the one or more heat sources comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 64. Themethod of claim 54, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 65. The methodof claim 54, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 66. The method of claim 54,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 67. The method ofclaim 54, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen.
 68. Themethod of claim 54, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 69. Themethod of claim 54, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 70. Themethod of claim 54, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 71. The methodof claim 54, wherein the produced mixture comprises condensablehydrocarbons. and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 72. The method of claim54, wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 73. The methodof claim 54, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 74. The method of claim 54,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 75. The method of claim 54, wherein theproduced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 76. The method of claim 54, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 77. The method of claim54, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 78. The method of claim 54,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 79. The method of claim 54, furthercomprising controlling formation conditions to produce a mixture ofcondensable hydrocarbons and H₂, wherein a partial pressure of H₂ withinthe mixture is greater than about 0.5 bar.
 80. The method of claim 79,wherein the partial pressure of H₂ is measured when the mixture is at aproduction well.
 81. The method of claim 54, further comprising alteringa pressure within the formation to inhibit production of hydrocarbonsfrom the formation having carbon numbers greater than about
 25. 82. Themethod of claim 54, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.83. The method of claim 54, further comprising: providing hydrogen (H₂)to the heated section to hydrogenate hydrocarbons within the section;and heating a portion of the section with heat from hydrogenation. 84.The method of claim 54, wherein the produced mixture comprises hydrogenand condensable hydrocarbons, the method further comprisinghydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 85. The method of claim 54,wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 86. The method of claim 54 wherein allowing the heat totransfer comprises substantially uniformly increasing a permeability ofa majority of the selected section.
 87. The method of claim 54, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons, as measured by the Fischer Assay.88. The method of claim 54, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well. 89.The method of claim 54, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 90. The method of claim 54, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 91. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; and heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 92. The method of claim 91, wherein the oneor more heat sources comprise at least two heat sources. and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.93. The method of claim 91, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 94. The method of claim 91, wherein the oneor more heat sources comprise electrical heaters.
 95. The method ofclaim 91, wherein the one or more heat sources comprise surface burners.96. The method of claim 91, wherein the one or more heat sourcescomprise flameless distributed combustors.
 97. The method of claim 91,wherein the one or more heat sources comprise natural distributedcombustors.
 98. The method of claim 91, further comprising controlling apressure and a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 99. The method of claim 91, further comprising controllingthe heat such that an average heating rate of the selected section isless than about 1° C. per day during pyrolysis.
 100. The method of claim91, wherein providing heat from the one or more heat sources to at leastthe portion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heat sourceswherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./'day.101. The method of claim 91, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 102. The methodof claim 91, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 103. Themethod of claim 91, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 104. The method of claim 91,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 105. The method ofclaim 91, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 106.The method of claim 91, wherein the produced mixture comprisescondensable hydrocarbons. and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 107. The method of claim 91, wherein the produced mixturecomprises condensable hydrocarbons. and wherein less than about 1% byweight when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 108. The method of claim 91, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 109. The method of claim 91, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 110. The method of claim 91, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 111. The method of claim 91, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 112. The method of claim 91, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.113. The method of claim 91, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 114. Themethod of claim 91, wherein the produced mixture comprises ammonia andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 115. The method of claim 91, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 116. The method of claim 91, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barabsolute.
 117. The method of claim 91, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 118. The method of claim 117, wherein the partialpressure of H₂ is measured when the mixture is at a production well.119. The method of claim 91, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 120. The methodof claim 91, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.121. The method of claim 91, further comprising: providing hydrogen (H₂)to the heated section to hydrogenate hydrocarbons within the section;and heating a portion of the section with heat from hydrogenation. 122.The method of claim 91 wherein the produced mixture comprises hydrogenand condensable hydrocarbons, the method further comprisinghydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 123. The method of claim 91,wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 124. The method of claim 91, wherein allowing the heatto transfer comprises substantially uniformly increasing a permeabilityof a majority of the selected section.
 125. The method of claim 91,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.126. The method of claim 91, wherein producing the mixture comprisesproducing the mixture in a production well. and wherein at least about 7heat sources are disposed in the formation for each production well.127. The method of claim 91, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 128. The method of claim 91, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 129. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; controlling the heat from the one or more heat sourcessuch that an average temperature within at least a majority of theselected section of the formation is less than about 370° C. such thatproduction of a substantial amount of hydrocarbons having carbon numbersgreater than 25 is inhibited; controlling a pressure within at least amajority of the selected section of the formation, wherein thecontrolled pressure is at least 2.0 bar; and producing a mixture fromthe formation, wherein about 0.1% by weight of the produced mixture toabout 15% by weight of the produced mixture are olefins, and wherein anaverage carbon number of the produced mixture ranges from 1-25.
 130. Themethod of claim 129, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 131. The method of claim 129, whereincontrolling formation conditions comprises maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 132.The method of claim 129, wherein the one or more heat sources compriseelectrical heaters.
 133. The method of claim 129, wherein the one ormore heat sources comprise surface burners.
 134. The method of claim129, wherein the one or more heat sources comprise flameless distributedcombustors.
 135. The method of claim 129, wherein the one or more heatsources comprise natural distributed combustors.
 136. The method ofclaim 129, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 137. The method ofclaim 129, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 138. The method of claim 129, wherein providing heatfrom the one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 139. The methodof claim 129, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 140. The method of claim129, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 141. The method of claim 129, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 142.The method of claim 129, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 143. The method of claim 129, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 144. The method of claim 129, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 145. The method of claim 129,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 146. The method ofclaim 129, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 147. Themethod of claim 129, wherein the produced mixture comprises condensablehydrocarbons. and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 148. The method ofclaim 129, wherein the produced mixture comprises condensablehydrocarbons and wherein less than about 5% by weight of the condensablehydrocarbons comprises multi-ring aromatics with more than two rings.149. The method of claim 129, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 150. The method of claim129, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 151. The method of claim 129, wherein theproduced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 152. The method of claim 129, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 153. The method of claim129, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 154. The method of claim 129,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 155. The method ofclaim 154, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 156. The method of claim 129, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 157. The method of claim 129, further comprising:providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 158. The method of claim 129, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 159. The method of claim 129, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 160. The methodof claim 129, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 161. The method of claim 129, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 162. Themethod of claim 129, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well.
 163. Themethod of claim 129, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 164. The method of claim 129, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 165. The method of claim 129, further comprisingseparating the produced mixture into a gas stream and a liquid stream.166. The method of claim 129, further comprising separating the producedmixture into a gas stream and a liquid stream and separating the liquidstream into an aqueous stream and a non-aqueous stream.
 167. The methodof claim 129, wherein the produced mixture comprises H₂S, the methodfurther comprising separating a portion of the H₂S from non-condensablehydrocarbons.
 168. The method of claim 129 wherein the produced mixturecomprises CO₂, the method further comprising separating a portion of theCO₂ from non-condensable hydrocarbons.
 169. The method of claim 129,wherein the mixture is produced from a production well, wherein theheating is controlled such that the mixture can be produced from theformation as a vapor.
 170. The method of claim 129, wherein the mixtureis produced from a production well, the method further comprisingheating a wellbore of the production well to inhibit condensation of themixture within the wellbore.
 171. The method of claim 129, wherein themixture is produced from a production well, wherein a wellbore of theproduction well comprises a heater element configured to heat theformation adjacent to the wellbore, and further comprising heating theformation with the heater element to produce the mixture, wherein theproduced mixture comprise a large non-condensable hydrocarbon gascomponent and H₂.
 172. The method of claim 129, wherein the minimumpyrolysis temperature is about 270° C.
 173. The method of claim 129,further comprising maintaining the pressure within the formation aboveabout 2.0 bar absolute to inhibit production of fluids having carbonnumbers above
 25. 174. The method of claim 129, further comprisingcontrolling pressure within the formation in a range from aboutatmospheric pressure to about 100 bar absolute, as measured at awellhead of a production well to control an amount of condensable fluidswithin the produced mixture, wherein the pressure is reduced to increaseproduction of condensable fluids, and wherein the pressure is increasedto increase production of non-condensable fluids.
 175. The method ofclaim 129, further comprising controlling pressure within the formationin a range from about atmospheric pressure to about 100 bar absolute, asmeasured at a wellhead of a production well, to control an API gravityof condensable fluids within the produced mixture, wherein the pressureis reduced to decrease the API gravity, and wherein the pressure isincreased to reduce the API gravity.
 176. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation: controlling a pressure within atleast a majority of the selected section of the formation, wherein thecontrolled pressure is at least about 2.0 bar absolute; and producing amixture from the formation.
 177. The method of claim 176, whereincontrolling the pressure comprises controlling the pressure with a valvecoupled to at least one of the one or more heat sources.
 178. The methodof claim 176, wherein controlling the pressure comprises controlling thepressure with a valve coupled to a production well located in theformation.
 179. The method of claim 176, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 180. Themethod of claim 176, wherein controlling formation conditions comprisesmaintaining a temperature within the selected section within a pyrolysistemperature range.
 181. The method of claim 176, wherein the one or moreheat sources comprise electrical heaters.
 182. The method of claim 176,wherein the one or more heat sources comprise surface burners.
 183. Themethod of claim 176, wherein the one or more heat sources compriseflameless distributed combustors.
 184. The method of claim 176, whereinthe one or more heat sources comprise natural distributed combustors.185. The method of claim 176, further comprising controlling atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.186. The method of claim 176, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 187. The method of claim 176,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heat sourceswherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.188. The method of claim 176, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 189. The methodof claim 176, wherein providing heat from the one or more heat sourcescomprises heating the selected section such that a thermal conductivityof at least a portion of the selected section is greater than about 0.5W/(m ° C.).
 190. The method of claim 176, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 191. The method of claim 176, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 192.The method of claim 176, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 193. The method of claim 176, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 194. The method of claim 176, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 195. The method of claim 176,wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 196. The method ofclaim 176, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 197. Themethod of claim 176, wherein the produced mixture comprises condensablehydrocarbons. and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 198. The method ofclaim 176, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 199. The method of claim 176, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 200. The methodof claim 176, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 201. The method of claim176, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 202. The method of claim 176, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 203. The method of claim176, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 204. The method of claim 176,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 205. The method ofclaim 204, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 206. The method of claim 176, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 207. The method of claim 176, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 208. The method of claim 176, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 209. The method of claim 176, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 210. The method of claim 176, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 211. The methodof claim 176, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 212. The method of claim 176, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 213. Themethod of claim 176, wherein producing the mixture from the formationcomprises producing the mixture in a production well, and wherein atleast about 7 heat sources are disposed in the formation for eachproduction well.
 214. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation: allowing the heat totransfer from the one or more heat sources to a selected section of theformation; and controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bar absolute; controlling the heat from the one or moreheat sources such that an average temperature within at least a majorityof the selected section of the formation is less than about 375° C.; andproducing a mixture from the formation.
 215. The method of claim 214,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 216. The method of claim 214, wherein controlling formationconditions comprises maintaining a temperature within the selectedsection within a pyrolysis temperature range.
 217. The method of claim214, wherein the one or more heat sources comprise electrical heaters.218. The method of claim 214, wherein the one or more heat sourcescomprise surface burners.
 219. The method of claim 214, wherein the oneor more heat sources comprise Blameless distributed combustors.
 220. Themethod of claim 214, wherein the one or more heat sources comprisenatural distributed combustors.
 221. The method of claim 214, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 222. The method of claim 214,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 223. The method of claim 214, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heat sources, wherein the formation has an averageheat capacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 224. The method of claim 214, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 225. The method of claim 214, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 226. The method of claim214, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 227. The method of claim214, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 228. The method of claim 214,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 229. The method of claim 214,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 230. The method ofclaim 214, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 231.The method of claim 214, wherein the produced mixture comprisescondensable hydrocarbons. and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 232. The method of claim 214, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 233. The method of claim 214, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 234. The method of claim 214, wherein the producedmixture comprises condensable hydrocarbons. and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 235. The method of claim 214, wherein the produced mixturecomprises condensable hydrocarbons. and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 236. The method of claim 214, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 237. The method of claim 214, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.238. The method of claim 214, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component. and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 239. Themethod of claim 214, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 240. The method of claim 214, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 241. The method of claim 214, wherein controlling the heatfurther comprises controlling the heat such that coke production isinhibited.
 242. The method of claim 214, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 243. The method of claim 242, wherein the partialpressure of H₂ is measured when the mixture is at a production well.244. The method of claim 214, further comprising altering the pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 245. The methodof claim 214, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.246. The method of claim 214 further comprising: providing hydrogen (H₂)to the heated section to hydrogenate hydrocarbons within the section;and heating a portion of the section with heat from hydrogenation. 247.The method of claim 214, wherein the produced mixture comprises hydrogenand condensable hydrocarbons, the method further comprisinghydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 248. The method of claim 214,wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 249. The method of claim 214, wherein allowing the heatto transfer comprises substantially uniformly increasing a permeabilityof a majority of the selected section.
 250. The method of claim 214,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.251. The method of claim 214, wherein producing the mixture comprisesproducing the mixture in a production well. and wherein at least about 7heat sources are disposed in the formation for each production well.252. The method of claim 214, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 253. The method of claim 214, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 254. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heat sources to at least a portion of the formation, allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; producing a mixture from the formation, wherein atleast a portion of the mixture is produced during the pyrolysis and themixture moves through the formation in a vapor phase; and maintaining apressure within at least a majority of the selected section above about2.0 bar absolute.
 255. The method of claim 254, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.256. The method of claim 254, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 257. The method of claim 254, wherein theone or more heat sources comprise electrical heaters.
 258. The method ofclaim 254, wherein the one or more heat sources comprise surfaceburners.
 259. The method of claim 254, wherein the one or more heatsources comprise flameless distributed combustors.
 260. The method ofclaim 254, wherein the one or more heat sources comprise naturaldistributed combustors.
 261. The method of claim 254, further comprisingcontrolling the pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 262. The method of claim 254,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 263. The method of claim 254, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heat sources, wherein the formation has an averageheat capacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 264. The method of claim 254, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 265. The method of claim 254, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 266. The method of claim254, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 267. The method of claim254, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 268. The method of claim 254,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 269. The method of claim 254,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 270. The method ofclaim 254, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 271.The method of claim 254, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 272. The method of claim 254, wherein the produced mixturecomprises condensable hydrocarbons. and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 273. The method of claim 254, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 274. The method of claim 254, wherein the producedmixture comprises condensable hydrocarbons. and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 275. The method of claim 254, wherein the produced mixturecomprises condensable hydrocarbons. and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 276. The method of claim 254, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 277. The method of claim 254, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.278. The method of claim 254, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 279. Themethod of claim 254, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 280. The method of claim 254, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 281. The method of claim 254, wherein the pressure ismeasured at a wellhead of a production well.
 282. The method of claim254, wherein the pressure is measured at a location within a wellbore ofthe production well.
 283. The method of claim 254, wherein the pressureis maintained below about 100 bar absolute.
 284. The method of claim254, further comprising controlling formation conditions to produce amixture of condensable hydrocarbons and H₂, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bar.
 285. The methodof claim 284, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 286. The method of claim 254, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 287. The method of claim 254, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 288. The method of claim 254, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 289. The method of claim 254, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 290. The method of claim 254, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 291. The methodof claim 254, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 292. The method of claim 254, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 293. Themethod of claim 254, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well.
 294. Themethod of claim 254, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 295. The method of claim 254, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 296. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; maintaining a pressure within at least a majority of theselected section of the formation above 2.0 bar absolute; and producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity higher than an APIgravity of condensable hydrocarbons in a mixture producible from theformation at the same temperature and at atmospheric pressure.
 297. Themethod of claim 296, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 298. The method of claim 296, whereincontrolling formation conditions comprises maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 299.The method of claim 296, wherein the one or more heat sources compriseelectrical heaters.
 300. The method of claim 296, wherein the one ormore heat sources comprise surface burners.
 301. The method of claim296, wherein the one or more heat sources comprise flameless distributedcombustors.
 302. The method of claim 296, wherein the one or more heatsources comprise natural distributed combustors.
 303. The method ofclaim 296, further comprising controlling the pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 304. The method ofclaim 296, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 305. The method of claim 296, wherein providing heatfrom the one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 306. The methodof claim 296, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 307. The method of claim296, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 308. The method of claim 296, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 309. The method of claim 296, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 310.The method of claim 296, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 311. Themethod of claim 296, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 312. The method of claim 296, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 313. The method of claim 296, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 314. The method of claim 296,wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 315. The method ofclaim 296, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 316. Themethod of claim 296, wherein the produced mixture comprises condensablehydrocarbons. and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 317. The method ofclaim 296, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 318. The method of claim 296, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 319. The methodof claim 296, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 320. The method of claim296, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 321. The method of claim 296, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 322. The method of claim296, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 323. The method of claim 296,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 324. The method ofclaim 296, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 325. The method of claim 296, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 326. The method of claim 296, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 327. The method of claim 296, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 328. The method of claim 296, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 329. The method of claim 296, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 330. The methodof claim 296, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 331. The method of claim 296, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 332. Themethod of claim 296, wherein producing the mixture comprises producingthe mixture in a production well and wherein at least about 7 heatsources are disposed in the formation for each production well.
 333. Themethod of claim 296, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 334. The method of claim 296, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 335. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; maintaining a pressure within at least a majority of theselected section of the formation to above 2.0 bar absolute; andproducing a fluid from the formation, wherein condensable hydrocarbonswithin the fluid comprise an atomic hydrogen to atomic carbon ratio ofgreater than about 1.75.
 336. The method of claim 335, wherein the oneor more heat sources comprise at least two heat sources. and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.337. The method of claim 335, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 338. The method of claim 335, wherein theone or more heat sources comprise electrical heaters.
 339. The method ofclaim 335, wherein the one or more heat sources comprise surfaceburners.
 340. The method of claim 335, wherein the one or more heatsources comprise flameless distributed combustors.
 341. The method ofclaim 335, wherein the one or more heat sources comprise naturaldistributed combustors.
 342. The method of claim 335, further comprisingcontrolling the pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature. or the temperature iscontrolled as a function of pressure.
 343. The method of claim 335,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 344. The method of claim 335, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heat sources, wherein the formation has an averageheat capacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 345. The method of claim 335, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 346. The method of claim 335, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 347. The method of claim335, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 348. The method of claim335, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 349. The method of claim 335,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 350. The method of claim 335,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 351. The method ofclaim 335, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 352.The method of claim 335, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 351. The method of claim 335, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 354. The method of claim 335, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 355. The method of claim 335, wherein the producedmixture comprises condensable hydrocarbons. and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 356. The method of claim 335, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 357. The method of claim 335, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 358. The method of claim 335, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.359. The method of claim 335, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 360. Themethod of claim 335, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 361. The method of claim 335, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 362. The method of claim 335, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 363. The method of claim 335, wherein the partialpressure of H₂ is measured when the mixture is at a production well.364. The method of claim 335, further comprising altering the pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 365. The methodof claim 335, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.366. The method of claim 335, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 367. The method of claim 335, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 368. Themethod of claim 335, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 369. The method of claim 335, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 370.The method of claim 335, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 371. The method of claim 335, whereinproducing the mixture comprises producing the mixture in a productionwell. and wherein at least about 7 heat sources are disposed in theformation for each production well.
 372. The method of claim 335,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 373.The method of claim 335, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 374. A method oftreating a hydrocarbon containing formation in situ. comprising:providing heat from one or more heat sources to at least a portion ofthe formation: allowing the heat to transfer from the one or more heatsources to a selected section of the formation; maintaining a pressurewithin at least a majority of the selected section of the formation toabove 2.0 bar absolute; and producing a mixture from the formation,wherein the produced mixture comprises a higher amount ofnon-condensable components as compared to non-condensable componentsproducible from the formation under the same temperature conditions andat atmospheric pressure.
 375. The method of claim 374, wherein the oneor more heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.376. The method of claim 374, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 377. The method of claim 374, wherein theone or more heat sources comprise electrical heaters.
 378. The method ofclaim 374, wherein the one or more heat sources comprise surfaceburners.
 379. The method of claim 374, wherein the one or more heatsources comprise flameless distributed combustors.
 380. The method ofclaim 374, wherein the one or more heat sources comprise naturaldistributed combustors.
 381. The method of claim 374, further comprisingcontrolling the pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 382. The method of claim 374,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 383. The method of claim 374, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heat sources, wherein the formation has an averageheat capacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 384. The method of claim 374, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 385. The method of claim 374, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 386. The method of claim374, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 387. The method of claim374, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 388. The method of claim 374,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 389. The method of claim 374,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 390. The method ofclaim 374, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 391.The method of claim 374, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 392. The method of claim 374, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 393. The method of claim 374, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 394. The method of claim 374, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 395. The method of claim 374, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 396. The method of claim 374, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 397. The method of claim 374, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.398. The method of claim 374, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 399. Themethod of claim 374, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 400. The method of claim 374, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 401. The method of claim 374, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 402. The method of claim 374, wherein the partialpressure of H₂ is measured when the mixture is at a production well.403. The method of claim 374, further comprising altering the pressurewithin the formation to inhibit production of hydrocarbons from theformation having car bon numbers greater than about
 25. 404. The methodof claim 374, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 405. The method ofclaim 374, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 406. The method of claim 374, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 407. Themethod of claim 374, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 408. The method of claim 374, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 409. Themethod of claim 374, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well.
 410. Themethod of claim 374, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 411. The method of claim 374, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 412. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation such that superimposed heat from the one or more heat sourcespyrolyzes at least about 20% by weight of hydrocarbons within theselected section of the formation; and producing a mixture from theformation.
 413. The method of claim 412, wherein the one or more heatsources comprise at least two heat sources. and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 414. Themethod of claim 412, wherein controlling formation conditions comprisesmaintaining a temperature within the selected section within a pyrolysistemperature range.
 415. The method of claim 412, wherein the one or moreheat sources comprise electrical heaters.
 416. The method of claim 412,wherein the one or more heat sources comprise surface burners.
 417. Themethod of claim 412, wherein the one or more heat sources compriseflameless distributed combustors.
 418. The method of claim 412, whereinthe one or more heat sources comprise natural distributed combustors.419. The method of claim 412, further comprising controlling a pressureand a temperature within at least a majority of the selected section ofthe formation, wherein the pressure is controlled as a function oftemperature or the temperature is controlled as a function of pressure.420. The method of claim 412, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 421. The method of claim 412,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.422. The method of claim 412, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 423. The methodof claim 412, wherein providing heat from the one or more heat sourcescomprises heating the selected formation such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C).
 424. The method of claim 412, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 425. The method of claim 412, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 426. The method of claim 412, wherein the produced mixturecomprises non-condensable hydrocarbons, and wherein about 0.1% by weightto about 15% by weight of the non-condensable hydrocarbons are olefins.427. The method of claim 412, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 428. The method of claim 412, wherein the produced mixturecomprises condensable hydrocarbons. and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 429. The method of claim 412, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight. when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 430. The method of claim 412,wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 431. The method ofclaim 412, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 432. Themethod of claim 412, wherein the produced mixture comprises condensablehydrocarbons and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 433. The method ofclaim 412, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 434. The method of claim 412, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 435. The methodof claim 412, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 436. The method of claim412, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 437. The method of claim 412, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 438. The method of claim412, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 439. The method of claim 412,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 440. The method of claim 412,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 441. The method ofclaim 412, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 442. The method of claim 412, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 443. The method of claim 412, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 444. The method of claim 412, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 445. The method of claim 412, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 446. The method of claim 412, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 447. The methodof claim 412, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 448. The method of claim 412, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 449. Themethod of claim 412, wherein producing the mixture comprises producingthe mixture in a production well. and wherein at least about 7 heatsources are disposed in the formation for each production well.
 450. Themethod of claim 412, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 451. The method of claim 412, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 452. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation: allowing the heat totransfer from the one or more heat sources to a selected section of theformation such that superimposed heat from the one or more heat sourcespyrolyzes at least about 20% of hydrocarbons within the selected sectionof the formation; and producing a mixture from the formation, whereinthe mixture comprises a condensable component having an API gravity ofat least about 25°.
 453. The method of claim 452, wherein the one ormore heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.454. The method of claim 452, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 455. The method of claim 452, wherein theone or more heat sources comprise electrical heaters.
 456. The method ofclaim 452, wherein the one or more heat sources comprise surfaceburners.
 457. The method of claim 452, wherein the one or more heatsources comprise flameless distributed combustors.
 458. The method ofclaim 452, wherein the one or more heat sources comprise naturaldistributed combustors.
 459. The method of claim 452, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation wherein the pressure is controlledas a function of temperature, or the temperature is controlled as afunction of pressure.
 460. The method of claim 452, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 461. Themethod of claim 452, wherein providing heat from the one or more heatsources to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 462. The method of claim 452, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 463. The method of claim 452, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 464. The method of claim452, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 465. The method of claim 452,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 466. The method of claim 452,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 467. The method ofclaim 452, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 1% by weight. when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 468.The method of claim 452, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight. whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 469. The method of claim 452, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 470. The method of claim 452, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 471. The method of claim 452, wherein the producedmixture comprises condensable hydrocarbons. and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 472. The method of claim 452, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 473. The method of claim 452, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 474. The method of claim 452, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.475. The method of claim 452, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 476. Themethod of claim 452, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 477. The method of claim 452, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 478. The method of claim 452, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barabsolute.
 479. The method of claim 452, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 480. The method of claim 452, wherein the partialpressure of H₂ is measured when the mixture is at a production well.481. The method of claim 452, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 482. The methodof claim 452, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.483. The method of claim 452, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 484. The method of claim 452, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 485. Themethod of claim 452, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 486. The method of claim 452, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 487.The method of claim 452, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 488. The method of claim 452, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 489. The method of claim 452,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 490.The method of claim 452, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 491. A method oftreating a layer of a hydrocarbon containing formation in situ,comprising: providing heat from one or more heat sources to at least aportion of the layer, wherein the one or more heat sources arepositioned proximate an edge of the layer; allowing the heat to transferfrom the one or more heat sources to a selected section of the layersuch that superimposed heat from the one or more heat sources pyrolyzesat least some hydrocarbons within the selected section of the formation;and producing a mixture from the formation.
 492. The method of claim491, wherein the one or more heat sources are laterally spaced from acenter of the layer.
 493. The method of claim 491, wherein the one ormore heat sources are positioned in a staggered line.
 494. The method ofclaim 491, wherein the one or more heat sources positioned proximate theedge of the layer can increase an amount of hydrocarbons produced perunit of energy input to the one or more heat sources.
 495. The method ofclaim 491, wherein the one or more heat sources positioned proximate theedge of the layer can increase the volume of formation undergoingpyrolysis per unit of energy input to the one or more heat sources. 496.The method of claim 491, wherein the one or more heat sources compriseelectrical heaters.
 497. The method of claim 491, wherein the one ormore heat sources comprise surface burners.
 498. The method of claim491, wherein the one or more heat sources comprise flameless distributedcombustors.
 499. The method of claim 491, wherein the one or more heatsources comprise natural distributed combustors.
 500. The method ofclaim 491, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 501. The method ofclaim 491, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1.0° C. per dayduring pyrolysis.
 502. The method of claim 491, wherein providing heatfrom the one or more heat sources to at least the portion of the layercomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 503. The methodof claim 491, wherein providing heat from the one or more heat sourcescomprises heating the selected section such that a thermal conductivityof at least a portion of the selected section is greater than about 0.5W/(m ° C.).
 504. The method of claim 491, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 505. The method of claim 491, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 506.The method of claim 491, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 507. The method of claim 491, wherein the produced mixturecomprises condensable hydrocarbons. and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 508. The method of claim 491, wherein theproduced mixture comprises condensable hydrocarbons. and wherein lessthan about 1% by weight. when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 509. The method of claim 491,wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 510. The method ofclaim 491, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 511. Themethod of claim 491, wherein the produced mixture comprises condensablehydrocarbons. and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 512. The method ofclaim 491, wherein the produced mixture comprises condensablehydrocarbons and wherein less than about 5% by weight of the condensablehydrocarbons comprises multi-ring aromatics with more than two rings.513. The method of claim 491, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 514. The method of claim491, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 515. The method of claim 491, wherein theproduced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 516. The method of claim 491, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 517. The method of claim491, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 518. The method of claim 491,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 519. The method of claim 491,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 520. The method ofclaim 519, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 521. The method of claim 491, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 522. The method of claim 491, further comprisingcontrolling formation conditions, wherein controlling formationconditions comprises recirculating a portion of hydrogen from themixture into the formation.
 523. The method of claim 491, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 524. The method of claim 491, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 525. The method of claim 491, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 526. The methodof claim 491, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 527. The method of claim 491, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 528. Themethod of claim 491, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well.
 529. Themethod of claim 491, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 530. The method of claim 491, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 531. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; and controlling a pressure and a temperature within at leasta majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure; and producing a mixture fromthe formation.
 532. The method of claim 531, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.533. The method of claim 531, wherein controlling formation conditionscomprises maintaining a temperature within the selected section within apyrolysis temperature range.
 534. The method of claim 531, wherein theone or more heat sources comprise electrical heaters.
 535. The method ofclaim 531, wherein the one or more heat sources comprise surfaceburners.
 536. The method of claim 531, wherein the one or more heatsources comprise flameless distributed combustors.
 537. The method ofclaim 531, wherein the one or more heat sources comprise naturaldistributed combustors.
 538. The method of claim 531, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 539. Themethod of claim 531, wherein providing heat from the one or more heatsources to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heat sources, wherein the formation has an average heat capacity(C_(v)). and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 540. The method of claim 531, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 541. The method of claim 531, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 542. The method of claim531, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 543. The method of claim531, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 544. The method of claim 531,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 545. The method of claim 531,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 546. The method ofclaim 531, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 547.The method of claim 531, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis of the condensable hydrocarbons is oxygen.548. The method of claim 531, wherein the produced mixture comprisescondensable hydrocarbons. and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 549. The method of claim 531, wherein the produced mixturecomprises condensable hydrocarbons wherein about 5% by weight to about30% by weight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.550. The method of claim 531, wherein the produced mixture comprisescondensable hydrocarbons and wherein greater than about 20% by weight ofthe condensable hydrocarbons are aromatic compounds.
 551. The method ofclaim 531, wherein the produced mixture comprises condensablehydrocarbons and wherein less than about 5% by weight of the condensablehydrocarbons comprises multi-ring aromatics with more than two rings.552. The method of claim 531, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 553. The method of claim531, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 554. The method of claim 531, wherein theproduced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 555. The method of claim 531, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 556. The method of claim531, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 557. The method of claim 531,wherein the controlled pressure is at least about 2.0 bar absolute. 558.The method of claim 531, further comprising controlling formationconditions to produce a mixture of condensable hydrocarbons and H₂,wherein a partial pressure of H₂ within the mixture is greater thanabout 0.5 bar.
 559. The method of claim 531, wherein the partialpressure of H₂ is measured when the mixture is at a production well.560. The method of claim 531, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 561. The methodof claim 531, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.562. The method of claim 531, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 563. The method of claim 531, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 564. Themethod of claim 531, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 565. The method of claim 531, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 566.The method of claim 531, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 567. The method of claim 531, whereinproducing the mixture comprises producing the mixture in a productionwell. and wherein at least about 7 heat sources are disposed in theformation for each production well.
 568. The method of claim 531,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 569.The method of claim 531, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 570. A method oftreating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; allowing the heat to transfer from the one or more heatsources to a selected section of the formation to raise an averagetemperature within the selected section to, or above, a temperature thatwill pyrolyze hydrocarbons within the selected section; producing amixture from the formation; and controlling API gravity of the producedmixture to be greater than about 25 degrees API by controlling averagepressure and average temperature in the selected section such that theaverage pressure in the selected section is greater than the pressure(p) set forth in the following equation for an assessed averagetemperature (T) in the selected section: p=e ^([−44000/T+67]) where p ismeasured in psia and T is measured in ° Kelvin.
 571. The method of claim570, wherein the API gravity of the produced mixture is controlled to begreater than about 30 degrees API, and wherein the equation is: p=e^([−31000/T+51]).
 572. The method of claim 570, wherein the API gravityof the produced mixture is controlled to be greater than about 35degrees API, and wherein the equation is: p=e ^([−22000/T+38]).
 573. Themethod of claim 570, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 574. The method of claim 570, whereincontrolling the average temperature comprises maintaining a temperaturein the selected section within a pyrolysis temperature range.
 575. Themethod of claim 570, wherein the one or more heat sources compriseelectrical heaters.
 576. The method of claim 570, wherein the one ormore heat sources comprise surface burners.
 577. The method of claim570, wherein the one or more heat sources comprise flameless distributedcombustors.
 578. The method of claim 570, wherein the one or more heatsources comprise natural distributed combustors.
 579. The method ofclaim 570, further comprising controlling a temperature within at leasta majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 580. The method of claim 570,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 581. The method of claim 570, wherein providing heat from theone or more heat sources to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heat sources, wherein the formation has an averageheat capacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 582. The method of claim 570, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 583. The method of claim 570, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 584. The method of claim570, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 585. The method of claim 570,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 586. The method of claim 570,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 587. The method ofclaim 570, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 588.The method of claim 570, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 589. The method of claim 570, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 590. The method of claim 570, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 591. The method of claim 570, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 592. The method of claim 570, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 593. The method of claim 570, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 594. The method of claim 570, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.595. The method of claim 570, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 596. Themethod of claim 570, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 597. The method of claim 570, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 598. The method of claim 570, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 599. The method of claim 570, wherein the partialpressure of H₂ is measured when the mixture is at a production well.600. The method of claim 570, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 601. The methodof claim 570, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.602. The method of claim 570, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 603. The method of claim 570, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 604. Themethod of claim 570, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 605. The method of claim 570, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 606.The method of claim 570, wherein the heat is controlled to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 607. The method of claim 570, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heat sources are disposed in the formation foreach production well.
 608. The method of claim 570, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 609. The method of claim 570,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 610. A method of treating ahydrocarbon containing formation in situ, comprising: providing heat toat least a portion of a hydrocarbon containing formation such that atemperature (T) in a substantial part of the heated portion exceeds 270°C. and hydrocarbons are pyrolyzed within the heated portion of theformation; controlling a pressure (p) within at least a substantial partof the heated portion of the formation; whereinp_(bar)>e^([(−A/F)+B−26744]); wherein p is the pressure in bar absoluteand T is the temperature in degrees K, and A and B are parameters thatare larger than 10 and are selected in relation to the characteristicsand composition of the hydrocarbon containing formation and on therequired olefin content and carbon number of the pyrolyzed hydrocarbonfluids; and producing pyrolyzed hydrocarbon fluids from the heatedportion of the formation.
 611. The method of claim 610, wherein A isgreater than 14000 and B is greater than about 25 and a majority of theproduced pyrolyzed hydrocarbon fluids have an average carbon numberlower than 25 and comprise less than about 10% by weight of olefins.612. The method of claim 610, wherein T is less than about 390° C., p isgreater than about 1.4 bar, A is greater than about 44000, and b isgreater than about 67, and a majority of the produced pyrolyzedhydrocarbon fluids have an average carbon number less than 25 andcomprise less than 10% by weight of olefins.
 613. The method of claim610, wherein T is less than about 390° C., p is greater than about 2bar, A is less than about 57000, and b is less than about 83, and amajority of the produced pyrolyzed hydrocarbon fluids have an averagecarbon number lower than about
 21. 614. The method of claim 610, furthercomprising controlling the heat such that an average heating rate of theheated portion is less than about 3° C. per day during pyrolysis. 615.The method of claim 610, wherein providing heat from the one or moreheat sources to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 616. The method of claim 610, wherein heat istransferred substantially by conduction from one or more heat sourceslocated in one or more heat sources to the heated portion of theformation.
 617. The method of claim 616, wherein the heat sourcescomprise heaters in which hydrocarbons are either injected into aheaters or released by the hydrocarbon containing formation adjacent toa heater by an oxidant injected into the heater in or adjacent to whichthe combustion occurs and wherein at least part of the producedcombustion gases are vented to surface via the heater in which thecombustion occurs.
 618. The method of claim 617, wherein heat istransferred substantially by conduction from one or more heat sources tothe heated portion of the formation such that the thermal conductivityof at least part of the heated portion is substantially uniformlymodified to a value greater than about 0.6 W/m ° C. and the permeabilityof said part increases substantially uniformly to a value greater than 1Darcy.
 619. The method of claim 610, further comprising controllingformation conditions to produce a mixture of hydrocarbon fluids and H₂,wherein a partial pressure of H₂ within the mixture flowing through theformation is greater than 0.5 Bar.
 620. The method of claim 619, furthercomprising, hydrogenating a portion of the produced pyrolyzedhydrocarbon fluids with at least a portion of the produced hydrogen andheating the fluids with heat from hydrogenation.
 621. The method ofclaim 610, wherein the hydrocarbon containing formation is a coal seamand at least about 70% of the hydrocarbon content of the coal, when suchhydrocarbon content is measured by a Fischer assay, is produced from theheated portion of the formation.
 622. The method of claim 610, whereinthe substantially gaseous pyrolyzed hydrocarbon fluids are produced froma production well, the method further comprising heating a wellbore ofthe production well to inhibit condensation of the hydrocarbon fluidswithin the wellbore.
 623. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation to raise an average temperature within the selected sectionto, or above, a temperature that will pyrolyze hydrocarbons within theselected section; producing a mixture from the formation; andcontrolling a weight percentage of olefins of the produced mixture to beless than about 20% by weight by controlling average pressure andaverage temperature in the selected section such that the averagepressure in the selected section is greater than the pressure (p) setforth in the following equation for an assessed average temperature (7)in the selected section: p=e ^([−57000/T+83]) where p is measured inpsia and T is measured in ° Kelvin.
 624. The method of claim 623,wherein the weight percentage of olefins of the produced mixture iscontrolled to be less than about 10% by weight, and wherein the equationis: p=e ^([−16000/T+28]).
 625. The method of claim 623, wherein theweight percentage of olefins of the produced mixture is controlled to beless than about 5% by weight, and wherein the equation is:p=e^([−12000T/+22]).
 626. The method of claim 623, wherein the one ormore heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.627. The method of claim 623, wherein the one or more heat sourcescomprise electrical heaters.
 628. The method of claim 623, wherein theone or more heat sources comprise surface burners.
 629. The method ofclaim 623, wherein the one or more heat sources comprise flamelessdistributed combustors.
 630. The method of claim 623, wherein the one ormore heat sources comprise natural distributed combustors.
 631. Themethod of claim 623, further comprising controlling a temperature withinat least a majority of the selected section of the formation, whereinthe pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 632. The method ofclaim 631, wherein controlling an average temperature comprisesmaintaining a temperature within the selected section within a pyrolysistemperature range.
 633. The method of claim 623, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 3.0° C per day during pyrolysis.
 634. Themethod of claim 623, further comprising controlling the heat such thatan average heating rate of the selected section is less than about 1° C.per day during pyrolysis.
 635. The method of claim 623, whereinproviding heat from the one or more heat sources to at least the portionof formation comprises: heating a selected volume (V) of the hydrocarboncontaining formation from the one or more heat sources, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 636. Themethod of claim 623, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 637. The method of claim623, wherein providing heat from the one or more heat sources comprisesheating the selected formation such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 638. The method of claim 623, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 639. The method of claim 623, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 640.The method of claim 623, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 641. Themethod of claim 623, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 642. The method of claim 623, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 643. The method of claim 623, wherein theproduced mixture comprises condensable hydrocarbons. and wherein lessthan about 1% by weight. when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 644. The method of claim 623,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 645. The method ofclaim 623, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 646. Themethod of claim 623, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 647. The method ofclaim 623, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 648. The method of claim 623, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 649. The methodof claim 623, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 650. The method of claim623, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 651. The method of claim 623, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 652. The method of claim623, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 653. The method of claim 623,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 654. The method ofclaim 623, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 655. The method of claim 623, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 656. The method of claim 623, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 657. The method of claim 623, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 658. The method of claim 623, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 659. The method of claim 623, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 660. The methodof claim 623, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 661. The method of claim 623, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 662. Themethod of claim 623, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well.
 663. Themethod of claim 623, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 664. The method of claim 623, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 665. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation to raise an average temperature within the selected sectionto, or above, a temperature that will pyrolyze hydrocarbons within theselected section; producing a mixture from the formation; andcontrolling hydrocarbons having carbon numbers greater than 25 of theproduced mixture to be less than about 25% by weight by controllingaverage pressure and average temperature in the selected section suchthat the average pressure in the selected section is greater than thepressure (p) set forth in the following equation for an assessed averagetemperature (T) in the selected section: p=e ^([−14000/T+25]) where p ismeasured in psia and T is measured in ° Kelvin.
 666. The method of claim662, wherein the hydrocarbons having carbon numbers greater than 25 ofthe produced mixture is controlled to be less than about 20% by weight,and wherein the equation is: p=e ^([−16000/T+28]).
 667. The method ofclaim 662, wherein the hydrocarbons having carbon numbers greater than25 of the produced mixture is controlled to be less than about 15% byweight, and wherein the equation is: p=e ^([−18000/T+32]).
 668. Themethod of claim 662, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 669. The method of claim 662, whereinthe one or more heat sources comprise electrical heaters.
 670. Themethod of claim 662, wherein the one or more heat sources comprisesurface burners.
 671. The method of claim 662, wherein the one or moreheat sources comprise Blameless distributed combustors.
 672. The methodof claim 662, wherein the one or more heat sources comprise naturaldistributed combustors.
 673. The method of claim 662, further comprisingcontrolling a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 674. The method of claim 673, wherein controlling thetemperature comprises maintaining a temperature within the selectedsection within a pyrolysis temperature range.
 675. The method of claim662, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 676. The method of claim 662, wherein providing heatfrom the one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 677. The methodof claim 662, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 678. The method of claim662, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 679. The method of claim 662, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 680. The method of claim 662, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 681.The method of claim 662, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 682. The method of claim 662, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 683. The method of claim 662, wherein theproduced mixture comprises condensable hydrocarbons. and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 684. The method of claim 662,wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 685. The method ofclaim 662, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 686. Themethod of claim 662, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 687. The method ofclaim 662, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 688. The method of claim 662, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 689. The methodof claim 662, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 690. The method of claim662, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 691. The method of claim 662, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 692. The method of claim662, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 693. The method of claim 662,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 694. The method ofclaim 662, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 695. The method of claim 662, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 696. The method of claim 662, further comprising:providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 697. The method of claim 662, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 698. The method of claim 662, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 699. The methodof claim 662, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 700. The method of claim 662, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 701. Themethod of claim 662, wherein producing the mixture comprises producingthe mixture in a production well. and wherein at least about 7 heatsources are disposed in the formation for each production well.
 702. Themethod of claim 662, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 703. The method of claim 662, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 704. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation to raise an average temperature within the selected sectionto, or above, a temperature that will pyrolyze hydrocarbons within theselected section; producing a mixture from the formation; andcontrolling an atomic hydrogen to carbon ratio of the produced mixtureto be greater than about 1.7 by controlling average pressure and averagetemperature in the selected section such that the average pressure inthe selected section is greater than the pressure (p) set forth in thefollowing equation for an assessed average temperature (T) in theselected section: p=e ^([−38000/T+61]) where p is measured in psia and Tis measured in ° Kelvin.
 705. The method of claim 704, wherein theatomic hydrogen to carbon ratio of the produced mixture is controlled tobe greater than about 1.8, and wherein the equation is: p=e^([−13000/T+24]).
 706. The method of claim 704, wherein the atomichydrogen to carbon ratio of the produced mixture is controlled to begreater than about 1.9, and wherein the equation is: p=e^([−8000/T+18]).
 707. The method of claim 704, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.708. The method of claim 704, wherein the one or more heat sourcescomprise electrical heaters.
 709. The method of claim 704, wherein theone or more heat sources comprise surface burners.
 710. The method ofclaim 704, wherein the one or more heat sources comprise flamelessdistributed combustors.
 711. The method of claim 704, wherein the one ormore heat sources comprise natural distributed combustors.
 712. Themethod of claim 704, further comprising controlling a temperature withinat least a majority of the selected section of the formation, whereinthe pressure is controlled as a function of temperature. or thetemperature is controlled as a function of pressure.
 713. The method ofclaim 712, wherein controlling the temperature comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 714. The method of claim 704, further comprising controlling theheat such that an average heating rate of the selected section is lessthan about 1° C. per day during pyrolysis.
 715. The method of claim 704,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.716. The method of claim 704, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 717. The methodof claim 704, wherein providing heat from the one or more heat sourcescomprises heating the selected section such that a thermal conductivityof at least a portion of the selected section is greater than about 0.5W/(m ° C).
 718. The method of claim 704, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 719. The method of claim 704, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 720.The method of claim 704, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 721. Themethod of claim 704, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 722. The method of claim 704, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen. 723 . The method of claim 704, wherein theproduced mixture comprises condensable hydrocarbons. and wherein lessthan about 1% by weight. when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 724. The method of claim 704,wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 725. The method ofclaim 704, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 726. Themethod of claim 704, wherein the produced mixture comprises condensablehydrocarbons. and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 727. The method ofclaim 704, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 728. The method of claim 704, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 729. The methodof claim 704, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 730. The method of claim704, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 731. The method of claim 704, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 732. The method of claim704, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 733. The method of claim 704,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 734. The method ofclaim 704, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 735. The method of claim 704, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 736. The method of claim 704, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 737. The method of claim 704, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 738. The method of claim 704, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 739. The method of claim 704, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 740. The methodof claim 704, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 741. The method of claim 704, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 742. Themethod of claim 704, wherein producing the mixture comprises producingthe mixture in a production well. and wherein at least about 7 heatsources are disposed in the formation for each production well.
 743. Themethod of claim 704, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 744. The method of claim 704, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 745. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least one portion of the formation: allowing the heat totransfer from the one or more heat sources to a selected section of theformation: controlling a pressure-temperature relationship within atleast the selected section of the formation by selected energy inputinto the one or more heat sources and by pressure release from theselected section through wellbores of the one or more heat sources; andproducing a mixture from the formation.
 746. The method of claim 745,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 747. The method of claim 745, wherein the one or more heatsources comprise at least two heat sources.
 748. The method of claim745, wherein the one or more heat sources comprise surface burners. 749.The method of claim 745, wherein the one or more heat sources compriseflameless distributed combustors.
 750. The method of claim 745, whereinthe one or more heat sources comprise natural distributed combustors.751. The method of claim 745, further comprising controlling thepressure-temperature relationship by controlling a rate of removal offluid from the formation.
 752. The method of claim 745, furthercomprising controlling the heat such that an average heating rate of theselected section is less than about 1° C. per day during pyrolysis. 753.The method of claim 745, wherein providing heat from the one or moreheat sources to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 754. The method of claim 745, wherein allowingthe heat to transfer comprises transferring heat substantially byconduction.
 755. The method of claim 745, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 756. The method of claim745, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 757. The method of claim745, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 758. The method of claim 745,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 759. The method of claim 745,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 760. The method ofclaim 745, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 1% by weight when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 761.The method of claim 745, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 762. The method of claim 745, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 763. The method of claim 745, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 764. The method of claim 745, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 765. The method of claim 745, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 766. The method of claim 745, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 767. The method of claim 745, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.768. The method of claim 745, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 769. Themethod of claim 745, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 770. The method of claim 745, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 771. The method of claim 745, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barabsolute.
 772. The method of claim 745, further comprising controllingformation conditions to produce a mixture of hydrocarbon fluids and H₂,wherein the partial pressure of H₂ within the mixture is greater thanabout 0.5 bar.
 773. The method of claim 745, further comprisingcontrolling formation conditions to produce a mixture of condensablehydrocarbons and H₂, wherein a partial pressure of H₂ within the mixtureis greater than about 0.5 bar.
 774. The method of claim 745, wherein thepartial pressure of H₂ is measured when the mixture is at a productionwell.
 775. The method of claim 745, further comprising altering apressure within the formation to inhibit production of hydrocarbons fromthe formation having carbon numbers greater than about
 25. 776. Themethod of claim 745, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.777. The method of claim 745, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 778. The method of claim 745, wherein the producedmixture comprises hydrogen and condensable hydrocarbons, the methodfurther comprising hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 779. Themethod of claim 745, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 780. The method of claim 745, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 781.The method of claim 745, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 782. The method of claim 745, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 783. The method of claim 745,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 784.The method of claim 745, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 785. A method oftreating a hydrocarbon containing formation in situ, comprising: heatinga selected volume (V) of the hydrocarbon containing formation, whereinformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 786. Themethod of claim 785, wherein heating a selected volume comprises heatingwith an electrical heater.
 787. The method of claim 785, wherein heatinga selected volume comprises heating with a surface burner.
 788. Themethod of claim 785, wherein heating a selected volume comprises heatingwith a flameless distributed combustor.
 789. The method of claim 785,wherein heating a selected volume comprises heating with a naturaldistributed combustors.
 790. The method of claim 785, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected volume of the formation, wherein the pressure is controlledas a function of temperature or the temperature is controlled as afunction of pressure.
 791. The method of claim 785, further comprisingcontrolling the heating such that an average heating rate of theselected volume is less than about 1° C. per day during pyrolysis. 792.The method of claim 785, wherein a value for CV is determined as anaverage heat capacity of two or more samples taken from the hydrocarboncontaining formation.
 793. The method of claim 785 wherein heating theselected volume comprises transferring heat substantially by conduction.794. The method of claim 785, wherein heating the selected volumecomprises heating the selected section such that a thermal conductivityof at least a portion of the selected section is greater than about 0.5W/(m ° C.).
 795. The method of claim 785, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 796. The method of claim 785, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 797.The method of claim 785, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 798. Themethod of claim 785, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 799. The method of claim 785, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 800. The method of claim 785, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 801. The method of claim 785,wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight. when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 802. The method ofclaim 785, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 803. Themethod of claim 785, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 804. The method ofclaim 785, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 805. The method of claim 785, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 806. The methodof claim 785, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 807. The method of claim785, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 808. The method of claim 785, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 809. The method of claim785, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer
 810. The method of claim 785,further comprising controlling a pressure within at least a majority ofthe selected volume of the formation, wherein the controlled pressure isat least about 2.0 bar absolute.
 811. The method of claim 785, furthercomprising controlling formation conditions to produce a mixture fromthe formation comprising condensable hydrocarbons and H₂, wherein apartial pressure of H₂ within the mixture is greater than about 0.5 bar.812. The method of claim 785, wherein the partial pressure of H₂ ismeasured when the mixture is at a production well.
 813. The method ofclaim 785, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 814. The method of claim 785, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 815. The method of claim785, further comprising: providing hydrogen (H₂) to the heated volume tohydrogenate hydrocarbons within the volume; and heating a portion of thevolume with heat from hydrogenation.
 816. The method of claim 785,wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 817. The method of claim 785, further comprisingincreasing a permeability of a majority of the selected volume togreater than about 100 millidarcy.
 818. The method of claim 785, furthercomprising substantially uniformly increasing a permeability of amajority of the selected volume.
 819. The method of claim 785, furthercomprising controlling the heat to yield greater than about 60% byweight of condensable hydrocarbons, as measured by the Fischer Assay.820. The method of claim 785, wherein producing the mixture comprisesproducing the mixture in a production well. and wherein at least about 7heat sources are disposed in the formation for each production well.821. The method of claim 785, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 822. The method of claim 785, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 823. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation to raise an average temperature within the selectedsection to, or above, a temperature that will pyrolyze hydrocarbonswithin the selected section; controlling heat output from the one ormore heat sources such that an average heating rate of the selectedsection rises by less than about 3° C. per day when the averagetemperature of the selected section is at, or above, the temperaturethat will pyrolyze hydrocarbons within the selected section; andproducing a mixture from the formation.
 824. The method of claim 823,controlling heat output comprises: raising the average temperaturewithin the selected section to a first temperature that is at or above aminimum pyrolysis temperature of hydrocarbons within the formation;limiting energy input into the one or more heat sources to inhibitincrease in temperature of the selected section; and increasing energyinput into the formation to raise an average temperature of the selectedsection above the first temperature when production of formation fluiddeclines below a desired production rate.
 825. The method of claim 823,controlling heat output comprises: raising the average temperaturewithin the selected section to a first temperature that is at or above aminimum pyrolysis temperature of hydrocarbons within the formation;limiting energy input into the one or more heat sources to inhibitincrease in temperature of the selected section; and increasing energyinput into the formation to raise an average temperature of the selectedsection above the first temperature when quality of formation fluidproduced from the formation falls below a desired quality.
 826. Themethod of claim 823, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section.
 827. The method of claim 823, wherein the one or moreheat sources comprise electrical heaters.
 828. The method of claim 823,wherein the one or more heat sources comprise surface burners.
 829. Themethod of claim 823, wherein the one or more heat sources compriseflameless distributed combustors.
 830. The method of claim 823, whereinthe one or more heat sources comprise natural distributed combustors.831. The method of claim 823, further comprising controlling a pressureand a temperature within at least a majority of the selected section ofthe formation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.832. The method of claim 823, wherein the heat is controlled that anaverage heating rate of the selected section is less than about 1.5° C.per day during pyrolysis.
 833. The method of claim 823, wherein the heatis controlled that an average heating rate of the selected section isless than about 1° C. per day during pyrolysis.
 834. The method of claim823, wherein providing heat from the one or more heat sources to atleast the portion of formation comprises: heating a selected volume (V)of the hydrocarbon containing formation from the one or more heatsources, wherein the formation has an average heat capacity (C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/dayprovided to the volume is equal to or less than Pwr, wherein Pwr iscalculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is theheating energy/day, h is an average heating rate of the formation, ρ_(B)is formation bulk density.
 835. The method of claim 823, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 836. The method of claim 823, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 837. The method of claim823, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 838. The method of claim823, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 839. The method of claim 823,wherein the produced mixture comprises condensable hydrocarbons, whereinthe condensable hydrocarbons have an olefin content is less than about2.5% by weight of the condensable hydrocarbons, and wherein the olefincontent is greater than about 0.1% by weight of the condensablehydrocarbons.
 840. The method of claim 823, wherein the produced mixturecomprises non-condensable hydrocarbons, wherein a molar ratio of etheneto ethane in the non-condensable hydrocarbons is less than about 0.15,and wherein the ratio of ethene to ethane is greater than about 0.001.841. The method of claim 823, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons is less than about 0.10 andwherein the ratio of ethene to ethane is greater than about 0.001. 842.The method of claim 823, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons is less than about 0.05 andwherein the ratio of ethene to ethane is greater than about 0.001. 843.The method of claim 823, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis of the condensable hydrocarbons isnitrogen.
 844. The method of claim 823, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight. when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 845. The method of claim 823, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight. when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 846. The method of claim 823,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 847. The method of claim823, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 848. The method of claim 823,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 849. The methodof claim 823, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 850. The method of claim 823,wherein the produced mixture comprises condensable hydrocarbons, andwherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 851. The method of claim 823, wherein theproduced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 852. The method of claim 823, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 853. The method of claim823, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 854. The method of claim 823,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 855. The method of claim 823,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 856. The method ofclaim 823, wherein the partial pressure of H₂, is measured when themixture is at a production well.
 857. The method of claim 823, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 858. The method of claim 823, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 859. The method of claim 823, furthercomprising: providing H₂ to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 860. The method of claim 823, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 861. The method of claim 823, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 862. The methodof claim 823, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 863. The method of claim 823, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 864. Themethod of claim 823, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well.
 865. Themethod of claim 823, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 866. The method of claim 823, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 867. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; to heat a selectedsection of the formation to an average temperature above about 270° C.;allowing the heat to transfer from the one or more heat sources to theselected section of the formation; controlling the heat from the one ormore heat sources such that an average heating rate of the selectedsection is less than about 3° C. per day during pyrolysis; and producinga mixture from the formation.
 868. The method of claim 867, wherein theone or more heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.869. The method of claim 867, wherein the one or more heat sourcescomprise electrical heaters.
 870. The method of claim 867, furthercomprising supplying electricity to the electrical heaters substantiallyduring non-peak hours.
 871. The method of claim 867, wherein the one ormore heat sources comprise surface burners.
 872. The method of claim867, wherein the one or more heat sources comprise flameless distributedcombustors.
 873. The method of claim 867, wherein the one or more heatsources comprise natural distributed combustors.
 874. The method ofclaim 867, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 875. The method ofclaim 867, wherein the heat is further controlled such that an averageheating rate of the selected section is less than about 3° C./day untilproduction of condensable hydrocarbons substantially ceases.
 876. Themethod of claim 867, wherein the heat is further controlled that anaverage heating rate of the selected section is less than about 1.5° C.per day during pyrolysis.
 877. The method of claim 867, wherein the heatis further controlled such that an average heating rate of the selectedsection is less than about 1° C. per day during pyrolysis.
 878. Themethod of claim 867, wherein providing heat from the one or more heatsources to at least the portion of formation comprises: heating aselected volume (V) of the hydrocarbon containing formation from the oneor more heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density.
 879. The method of claim 867, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 880. The method of claim 867, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 881. The method of claim867, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 882. The method of claim867, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 883. The method of claim 867,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 884. The method of claim 867,wherein the produced mixture comprises non-condensable hydrocarbons,wherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons is less than about 0.15, and wherein the ratio of ethene toethane is greater than about 0.001.
 885. The method of claim 867,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 886. The method ofclaim 867, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 887. Themethod of claim 867, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 888. Themethod of claim 867, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 889. Themethod of claim 867, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 890. The method ofclaim 867, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 891. The method of claim 867, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 892. The methodof claim 867, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 893. The method of claim867, wherein the produced mixture comprises a non-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 894. The method of claim 867, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 895. The method of claim867, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 896. The method of claim 867,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 897. The method of claim 867,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 898. The method ofclaim 897, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 899. The method of claim 867, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 900. The method of claim 867, wherein controllingformation conditions comprises recirculating a portion of hydrogen fromthe mixture into the formation.
 901. The method of claim 867, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 902. The method of claim 867, wherein theproduced mixture comprises hydrogen and condensable hydrocarbons, themethod further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 903. The method of claim 867, wherein allowing the heat totransfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 904. The methodof claim 867, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 905. The method of claim 867, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 906. Themethod of claim 867, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well.
 907. Themethod of claim 867, further comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 908. The method of claim 867, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 909. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; producing a mixture from the formation through at least oneproduction well: monitoring a temperature at or in the production well;and controlling heat input to raise the monitored temperature at a rateof less than about 3° C. per day.
 910. The method of claim 909, whereinthe one or more heat sources comprise at least two heat sources, andwherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 911. The method of claim 909, wherein the one or more heatsources comprise electrical heaters.
 912. The method of claim 909,wherein the one or more heat sources comprise surface burners.
 913. Themethod of claim 909, wherein the one or more heat sources compriseflameless distributed combustors.
 914. The method of claim 909, whereinthe one or more heat sources comprise natural distributed combustors.915. The method of claim 909, further comprising controlling a pressureand a temperature within at least a majority of the selected section ofthe formation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.916. The method of claim 909, wherein the heat is controlled that anaverage heating rate of the selected section is less than about 1° C.per day during pyrolysis.
 917. The method of claim 909, whereinproviding heat from the one or more heat sources to at least the portionof formation comprises: heating a selected volume (V) of the hydrocarboncontaining formation from the one or more heat sources, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B)is formation bulk density.918. The method of claim 909, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 919. The methodof claim 909, wherein providing heat from the one or more heat sourcescomprises heating the selected section such that a thermal conductivityof at least a portion of the selected section is greater than about 0.5W/(m ° C.).
 920. The method of claim 909, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 921. The method of claim 909, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 922.The method of claim 909, wherein the produced mixture comprisesnon-condensable hydrocarbons, wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons is less than about 0.15, and whereinthe ratio of ethene to ethane is greater than about 0.001.
 923. Themethod of claim 909, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 924.The method of claim 909, wherein the produced mixture comprisescondensable hydrocarbons. and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 925. The method of claim 909, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 926. The method of claim 909, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 927. The method of claim 909, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 928. The method of claim 909, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 929. The method of claim 909, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 930. The method of claim 909, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 5% by weight toabout 30% by weight of the condensable hydrocarbons are cycloalkanes.931. The method of claim 909, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable component, and wherein the hydrogen isless than about 80% by volume of the non-condensable component.
 932. Themethod of claim 909, wherein the produced mixture comprises ammonia, andwherein greater than about 0.05% by weight of the produced mixture isammonia.
 933. The method of claim 909, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 934. The method of claim 909, further comprising controllinga pressure within at least a majority of the selected section of theformation, wherein the controlled pressure is at least about 2.0 barabsolute.
 935. The method of claim 909, further comprising controllingformation conditions to produce a mixture of condensable hydrocarbonsand H₂, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 936. The method of claim 935, wherein the partialpressure of H₂ is measured when the mixture is at a production well.937. The method of claim 909, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 938. The methodof claim 909, wherein controlling formation conditions comprisesrecirculating a portion of hydrogen from the mixture into the formation.939. The method of claim 909, further comprising: providing H₂ to theheated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 940. Themethod of claim 909, wherein the produced mixture comprises hydrogen andcondensable hydrocarbons, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 941. The method of claim 909, wherein allowingthe heat to transfer comprises increasing a permeability of a majorityof the selected section to greater than about 100 millidarcy.
 942. Themethod of claim 909, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 943. The method of claim 909, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 944. Themethod of claim 909, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well.
 945. Themethod of claim 909, further comprising providing heat from three ormore beat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 946. The method of claim 909, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 947. A method of treating a hydrocarbon containingformation in situ. comprising: heating a portion of the formation to atemperature sufficient to support oxidation of hydrocarbons within theportion, wherein the portion is located substantially adjacent to awellbore; flowing an oxidant through a conduit positioned within thewellbore to a heat source zone within the portion, wherein the heatsource zone supports an oxidation reaction between hydrocarbons and theoxidant; reacting a portion of the oxidant with hydrocarbons to generateheat; and transferring generated heat substantially by conduction to apyrolysis zone of the formation to pyrolyze at least a portion of thehydrocarbons within the pyrolysis zone.
 948. The method of claim 947,wherein heating the portion of the formation comprises raising atemperature of the portion above about 400° C.
 949. The method of claim947, wherein the conduit comprises critical flow orifices, the methodfurther comprising flowing the oxidant through the critical floworifices to the heat source zone.
 950. The method of claim 947, furthercomprising removing reaction products from the heat source zone throughthe wellbore.
 951. The method of claim 947 further comprising removingexcess oxidant from the heat source zone to inhibit transport of theoxidant to the pyrolysis zone.
 952. The method of claim 947, furthercomprising transporting the oxidant from the conduit to the heat sourcezone substantially by diffusion.
 953. The method of claim 947, furthercomprising heating the conduit with reaction products being removedthrough the wellbore.
 954. The method of claim 947, wherein the oxidantcomprises hydrogen peroxide.
 955. The method of claim 947, wherein theoxidant comprises air.
 956. The method of claim 947, wherein the oxidantcomprises a fluid substantially free of nitrogen.
 957. The method ofclaim 947, further comprising limiting an amount of oxidant to maintaina temperature of the heat source zone less than about 1200° C.
 958. Themethod of claim 947, wherein heating the portion of the formationcomprises electrically heating the formation.
 959. The method of claim947, wherein heating the portion of the formation comprises heating theportion using exhaust gases from a surface burner.
 960. The method ofclaim 947, wherein heating the portion of the formation comprisesheating the portion with a flameless distributed combustor.
 961. Themethod of claim 947, further comprising controlling a pressure and atemperature within at least a majority of the pyrolysis zone, whereinthe pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 962. The method ofclaim 947, further comprising controlling the heat such that an averageheating rate of the pyrolysis zone is less than about 1° C. per dayduring pyrolysis.
 963. The method of claim 947, wherein heating theportion comprises heating the pyrolysis zone such that a thermalconductivity of at least a portion of the pyrolysis zone is greater thanabout 0.5 W/(m ° C.).
 964. The method of claim 947, further comprisingcontrolling a pressure within at least a majority of the pyrolysis zoneof the formation, wherein the controlled pressure is at least about 2.0bar absolute.
 965. The method of claim 947, further comprising:providing hydrogen (H₂) to the pyrolysis zone to hydrogenatehydrocarbons within the pyrolysis zone; and heating a portion of thepyrolysis zone with heat from hydrogenation.
 966. The method of claim947, wherein transferring generated heat comprises increasing apermeability of a majority of the pyrolysis zone to greater than about100 millidarcy.
 967. The method of claim 947, wherein transferringgenerated heat comprises substantially uniformly increasing apermeability of a majority of the pyrolysis zone.
 968. The method ofclaim 947, wherein the heating is controlled to yield greater than about60% by weight of condensable hydrocarbons, as measured by the FischerAssay.
 969. The method of claim 947, wherein the wellbore is locatedalong strike to reduce pressure differentials along a heated length ofthe wellbore.
 970. The method of claim 947, wherein the wellbore islocated along strike to increase uniformity of heating along a heatedlength of the wellbore.
 971. The method of claim 947, wherein thewellbore is located along strike to increase control of heating along aheated length of the wellbore.
 972. A method of treating a hydrocarboncontaining formation in situ, comprising: heating a portion of theformation to a temperature sufficient to support reaction ofhydrocarbons within the portion of the formation with an oxidant;flowing the oxidant into a conduit, and wherein the conduit is connectedsuch that the oxidant can flow from the conduit to the hydrocarbons;allowing the oxidant and the hydrocarbons to react to produce heat in aheat source zone; allowing heat to transfer from the heat source zone toa pyrolysis zone in the formation to pyrolyze at least a portion of thehydrocarbons within the pyrolysis zone; and removing reaction productssuch that the reaction products are inhibited from flowing from the heatsource zone to the pyrolysis zone.
 973. The method of claim 972, whereinheating the portion of the formation comprises raising the temperatureof the portion above about 400° C.
 974. The method of claim 972, whereinheating the portion of the formation comprises electrically heating theformation.
 975. The method of claim 972, wherein heating the portion ofthe formation comprises heating the portion using exhaust gases from asurface burner.
 976. The method of claim 972, wherein the conduitcomprises critical flow orifices, the method further comprising flowingthe oxidant through the critical flow orifices to the heat source zone.977. The method of claim 972, wherein the conduit is located within awellbore, wherein removing reaction products comprises removing reactionproducts from the heat source zone through the wellbore.
 978. The methodof claim 972, further comprising removing excess oxidant from the heatsource zone to inhibit transport of the oxidant to the pyrolysis zone.979. The method of claim 972, further comprising transporting theoxidant from the conduit to the heat source zone substantially bydiffusion.
 980. The method of claim 972, wherein the conduit is locatedwithin a wellbore, the method further comprising heating the conduitwith reaction products being removed through the wellbore to raise atemperature of the oxidant passing through the conduit.
 981. The methodof claim 972, wherein the oxidant comprises hydrogen peroxide.
 982. Themethod of claim 972, wherein the oxidant comprises air.
 983. The methodof claim 972, wherein the oxidant comprises a fluid substantially freeof nitrogen.
 984. The method of claim 972, further comprising limitingan a mount of oxidant to maintain a temperature of the heat source zoneless than about 1200° C. .
 985. The method of claim 972, furthercomprising limiting an amount of oxidant to maintain a temperature ofthe heat source zone at a temperature that inhibits production of oxidesof nitrogen.
 986. The method of claim 972, wherein heating a portion ofthe formation to a temperature sufficient to support oxidation ofhydrocarbons within the portion further comprises heating with aflameless distributed combustor.
 987. The method of claim 972, furthercomprising controlling a pressure and a temperature within at least amajority of the pyrolysis zone of the formation, wherein the pressure iscontrolled as a function of temperature. or the temperature iscontrolled as a function of pressure.
 988. The method of claim 972,further comprising controlling the heat such that an average heatingrate of the pyrolysis zone is less than about 1° C. per day duringpyrolysis.
 989. The method of claim 972, wherein allowing the heat totransfer comprises transferring heat substantially by conduction. 990.The method of claim 972, wherein allowing heat to transfer comprisesheating the pyrolysis zone such that a thermal conductivity of at leasta portion of the pyrolysis zone is greater than about 0.5 W/(m ° C.).991. The method of claim 972, further comprising controlling a pressurewithin at least a majority of the pyrolysis zone, wherein the controlledpressure is at least about 2.0 bar absolute.
 992. The method of claim972, further comprising: providing hydrogen (H₂) to the pyrolysis zoneto hydrogenate hydrocarbons within the pyrolysis zone; and heating aportion of the pyrolysis zone with heat from hydrogenation.
 993. Themethod of claim 972, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the pyrolysis zone to greaterthan about 100 millidarcy.
 994. The method of claim 972, whereinallowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the pyrolysis zone.
 995. Themethod of claim 972, further comprising controlling the heat to yieldgreater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 996. An in situ method for heating ahydrocarbon containing formation, comprising: heating a portion of theformation to a temperature sufficient to support reaction ofhydrocarbons within the portion of the formation with an oxidizingfluid, wherein the portion is located substantially adjacent to anopening in the formation; providing the oxidizing fluid to a heat sourcezone in the formation; allowing the oxidizing gas to react with at leasta portion of the hydrocarbons at the heat source zone to generate heatin the heat source zone; and transferring the generated heatsubstantially by conduction from the heat source zone to a pyrolysiszone in the formation.
 997. The method of claim 996, further comprisingtransporting the oxidizing fluid through the heat source zone bydiffusion.
 998. The method of claim 996, further comprising directing atleast a portion of the oxidizing fluid into the opening through orificesof a conduit disposed in the opening.
 999. The method of claim 996,further comprising controlling a flow of the oxidizing fluid withcritical flow orifices of a conduit disposed in the opening such that arate of oxidation is controlled.
 1000. The method of claim 996, whereina conduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the conduit.1001. The method of claim 996, wherein a conduit is disposed within theopening, the method further comprising removing an oxidation productfrom the formation through the conduit and transferring substantial heatfrom the oxidation product in the conduit to the oxidizing fluid in theconduit.
 1002. The method of claim 996, wherein a conduit is disposedwithin the opening, the method further comprising removing an oxidationproduct from the formation through the conduit, wherein a flow rate ofthe oxidizing fluid in the conduit is approximately equal to a flow rateof the oxidation product in the conduit.
 1003. The method of claim 996,wherein a conduit is disposed within the opening, the method furthercomprising removing an oxidation product from the formation through theconduit and controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 1004. The method of claim 996,wherein a center conduit is disposed within an outer conduit, andwherein the outer conduit is disposed within the opening, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theouter conduit.
 1005. The method of claim 996, wherein the heat sourcezone extends radially from the opening a width of less thanapproximately 0.15 m.
 1006. The method of claim 996, wherein heating theportion comprises applying electrical current to an electric heaterdisposed within the opening.
 1007. The method of claim 996, wherein thepyrolysis zone is substantially adjacent to the heat source zone. 1008.The method of claim 996, further comprising controlling a pressure and atemperature within at least a majority of the pyrolysis zone of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1009. The method of claim 996, further comprising controlling the heatsuch that an average heating rate of the pyrolysis zone is less thanabout 1° C. per day during pyrolysis.
 1010. The method of claim 996,wherein allowing the heat to transfer comprises transferring heatsubstantially by conduction.
 1011. The method of claim 996, whereinallowing heat to transfer comprises heating the portion such that athermal conductivity of at least a portion of the pyrolysis zone isgreater than about 0.5 W/(m ° C.).
 1012. The method of claim 996,further comprising controlling a pressure within at least a majority ofthe pyrolysis zone, wherein the controlled pressure is at least about2.0 bar absolute.
 1013. The method of claim 996, further comprising:providing hydrogen (H₂) to the pyrolysis zone to hydrogenatehydrocarbons within the pyrolysis zone; and heating a portion of thepyrolysis zone with heat from hydrogenation.
 1014. The method of claim996, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the pyrolysis zone to greater than about100 millidarcy.
 1015. The method of claim 996, wherein allowing the heatto transfer comprises substantially uniformly increasing a permeabilityof a majority of the pyrolysis zone.
 1016. The method of claim 996,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.1017. A method of treating a hydrocarbon containing formation in situ,comprising: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; producing amixture from the formation; and maintaining an average temperaturewithin the selected section above a minimum pyrolysis temperature andbelow a vaporization temperature of hydrocarbons having carbon numbersgreater than 25 to inhibit production of a substantial amount ofhydrocarbons having carbon numbers greater than 25 in the mixture. 1018.The method of claim 1017, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 1019. The method of claim 1017,wherein maintaining the average temperature within the selected sectioncomprises maintaining the temperature within a pyrolysis temperaturerange.
 1020. The method of claim 1017, wherein the one or more heatsources comprise electrical heaters.
 1021. The method of claim 1017,wherein the one or more heat sources comprise surface burners.
 1022. Themethod of claim 1017, wherein the one or more heat sources compriseflameless distributed combustors.
 1023. The method of claim 1017,wherein the one or more heat sources comprise natural distributedcombustors.
 1024. The method of claim 1017, wherein the minimumpyrolysis temperature is greater than about 270° C.
 1025. The method ofclaim 1017, wherein the vaporization temperature is less thanapproximately 450° C at atmospheric pressure.
 1026. The method of claim1017, further comprising controlling a pressure and a temperature withinat least a majority of the selected section of the formation, whereinthe pressure is controlled as a function of temperature or thetemperature is controlled as a function of pressure.
 1027. The method ofclaim 1017, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 1028. The method of claim 1017, wherein providing heatfrom the one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C,), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B)is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1029. The methodof claim 1017, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1030. The method of claim1017, wherein providing heat from the one or more heat sources comprisesheating the selected formation such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1031. The method of claim 1017, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1032. The method of claim 1017, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1033.The method of claim 1017, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 1034. Themethod of claim 1017, wherein the produced mixture comprisesnon-condensable hydrocarbons, wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons is less than about
 0. 15, andwherein the ratio of ethene to ethane is greater than about 0.001. 1035.The method of claim 1017, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 1036. The method of claim 1017, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 1037. The method of claim 1017, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 1038. The method of claim 1017,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 1039. The method of claim1017, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 1040. The method of claim 1017,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 1041. Themethod of claim 1017, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 1042. The method of claim1017, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 1043. The method of claim 1017, whereinthe produced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1044. The method of claim 1017, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1045. The method of claim1017, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1046. The method of claim 1017,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 1047. The method of claim 1017,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1048. The method ofclaim 1047, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 1049. The method of claim 1017, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1050. The method of claim1017, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1051. The method of claim1017, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1052. The method of claim 1017, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1053. Themethod of claim 1017, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1054. The method of claim 1017, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1055. Themethod of claim 1017, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1056.The method of claim 1017, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1057. The method of claim 1017, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1058. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; controlling a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than 25; and producing a mixture from the formation.
 1059. Themethod of claim 1058, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1060. The method of claim 1058,wherein the one or more heat sources comprise electrical heaters. 1061.The method of claim 1058, wherein the one or more heat sources comprisesurface burners.
 1062. The method of claim 1058, wherein the one or moreheat sources comprise flameless distributed combustors.
 1063. The methodof claim 1058, wherein the one or more heat sources comprise naturaldistributed combustors.
 1064. The method of claim 1058, furthercomprising controlling a temperature within at least a majority of theselected section of the formation, wherein the pressure is controlled asa function of temperature, or the temperature is controlled as afunction of pressure.
 1065. The method of claim 1064, whereincontrolling the temperature comprises maintaining a temperature withinthe selected section within a pyrolysis temperature range.
 1066. Themethod of claim 1058, further comprising controlling the heat such thatan average heating rate of the selected section is less than about 1° C.per day during pyrolysis.
 1067. The method of claim 1058, whereinproviding heat from the one or more heat sources to at least the portionof formation comprises: heating a selected volume (V) of the hydrocarboncontaining formation from the one or more heat sources, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 1068. Themethod of claim 1058, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1069. The method of claim1058, wherein providing heat from the one or more heat sources comprisesheating the selected formation such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1070. The method of claim 1058, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1071. The method of claim 1058, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1072.The method of claim 1058, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 1073. Themethod of claim 1058, wherein the produced mixture comprisesnon-condensable hydrocarbons, wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons is less than about 0.15, and whereinthe ratio of ethene to ethane is greater than about 0.001.
 1074. Themethod of claim 1058, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight. when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1075.The method of claim 1058, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1076. The method of claim 1058, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1077. The method of claim 1058, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1078. The method of claim 1058, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1079. The method of claim 1058, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1080. The method of claim 1058, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1081. The method of claim 1058, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1082. The method of claim 1058, wherein the producedmixture comprises anon-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1083. The method of claim 1058, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1084. The method of claim1058, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1085. The method of claim 1058,further comprising controlling the pressure within at least a majorityof the selected section of the formation, wherein the controlledpressure is at least about 2.0 bar absolute.
 1086. The method of claim1058, further comprising controlling formation conditions to produce amixture of condensable hydrocarbons and H₂, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bar.
 1087. The methodof claim 1086, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 1088. The method of claim 1058, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1089. The method of claim1058, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1090. The method of claim1058, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1091. The method of claim 1058, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1092. Themethod of claim 1058, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1093. The method of claim 1058, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1094. Themethod of claim 1058, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1095.The method of claim 1058, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1096. The method of claim 1058, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1097. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; and producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 1098. The method of claim 1097, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.1099. The method of claim 1097, wherein the one or more heat sourcescomprise electrical heaters.
 1100. The method of claim 1097, wherein theone or more heat sources comprise surface burners.
 1101. The method ofclaim 1097, wherein the one or more heat sources comprise flamelessdistributed combustors.
 1102. The method of claim 1097, wherein the oneor more heat sources comprise natural distributed combustors.
 1103. Themethod of claim 1097, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1104. The method of claim 1097, wherein controlling the temperaturecomprises maintaining the temperature within the selected section withina pyrolysis temperature range.
 1105. The method of claim 1097, furthercomprising controlling the heat such that an average heating rate of theselected section is less than about 1° C. per day during pyrolysis.1106. The method of claim 1097, wherein providing heat from the one ormore heat sources to at least the portion of formation comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heat sources, wherein the formation has an averageheat capacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1107. The method of claim 1097, whereinallowing the heat to transfer comprises transferring heat substantiallyby conduction.
 1108. The method of claim 1097, wherein providing heatfrom the one or more heat sources comprises heating the selectedformation such that a thermal conductivity of at least a portion of theselected section is greater than about 0.5 W/(m ° C).
 1109. The methodof claim 1097, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 1110. Themethod of claim 1097, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 1111. The method of claim1097, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe non-condensable hydrocarbons are olefins.
 1112. The method of claim1097, wherein the produced mixture comprises non-condensablehydrocarbons, wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons is less than about 0.15, and wherein theratio of ethene to ethane is greater than about 0.001.
 1113. The methodof claim 1097, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1114.The method of claim 1097, wherein the produced mixture comprisescondensable hydrocarbons. and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1115. The method of claim 1097, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1116. The method of claim 1097, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1117. The method of claim 1097, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1118. The method of claim 1097, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1119. The method of claim 1097, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1120. The method of claim 1097, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1121. The method of claim 1097, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1122. The method of claim 1097, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1123. The method of claim1097, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1124. The method of claim 1097,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 1125. The method of claim 1097,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1126. The method ofclaim 1125, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 1127. The method of claim 1097, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1128. The method of claim 1097, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1129. The method of claim1097, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1130. The method of claim1097, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1131. The method of claim 1097, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1132. Themethod of claim 1097, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1133. The method of claim 1097, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1134. Themethod of claim 1097, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1135.The method of claim 1097, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1136. The method of claim 1097, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1137. A method of treating a hydrocarbon containingformation in situ. comprising: heating a section of the formation to apyrolysis temperature from at least a first heat source, a second heatsource and a third heat source, and wherein the first heat source, thesecond heat source and the third heat source are located along aperimeter of the section; controlling heat input to the first heatsource, the second heat source and the third heat source to limit aheating rate of the section to a rate configured to produce a mixturefrom the formation with an olefin content of less than about 15% byweight of condensable fluids (on a dry basis) within the producedmixture; and producing the mixture from the formation through aproduction well.
 1138. The method of claim 1137, wherein superpositionof heat form the first heat source, second heat source, and third heatsource pyrolyzes a portion of the hydrocarbons within the formation tofluids
 1139. The method of claim 1137, wherein the pyrolysis temperatureis between about 270° C. and about 400° C.
 1140. The method of claim1137, wherein the first heat source is operated for less than abouttwenty four hours a day.
 1141. The method of claim 1137, wherein thefirst heat source comprises an electrical heater.
 1142. The method ofclaim 1137, wherein the first heat source comprises a surface burner.1143. The method of claim 1137, wherein the first heat source comprisesa flameless distributed combustor.
 1144. The method of claim 1137,wherein the first heat source, second heat source and third heat sourceare positioned substantially at apexes of an equilateral triangle. 1145.The method of claim 1137, wherein the production well is locatedsubstantially at a geometrical center of the first heat source, secondheat source, and third heat source.
 1146. The method of claim 1137,further comprising a fourth heat source, fifth heat source, and sixthheat source located along the perimeter of the section.
 1147. The methodof claim 1146, wherein the heat sources are located substantially atapexes of a regular hexagon.
 1148. The method of claim 1147, wherein theproduction well is located substantially at a center of the hexagon.1149. The method of claim 1137, further comprising controlling apressure and a temperature within at least a majority of the section ofthe formation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1150. The method of claim 1137, wherein controlling the temperaturecomprises maintaining the temperature within the selected section withina pyrolysis temperature range.
 1151. The method of claim 1137, furthercomprising controlling the heat such that an average heating rate of thesection is less than about 3° C. per day during pyrolysis.
 1152. Themethod of claim 1137, further comprising controlling the heat such thatan average heating rate of the section is less than about 1° C. per dayduring pyrolysis.
 1153. The method of claim 1137, wherein providing heatfrom the one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1154. The methodof claim 1137, wherein heating the section of the formation comprisestransferring heat substantially by conduction.
 1155. The method of claim1137, wherein providing heat from the one or more heat sources comprisesheating the section such that a thermal conductivity of at least aportion of the section is greater than about 0.5 W/(m ° C.).
 1156. Themethod of claim 1137, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 1157. Themethod of claim 1137, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 1158. The method of claim1137, wherein the produced mixture comprises non-condensablehydrocarbons, wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons is less than about
 0. 15, and wherein theratio of ethene to ethane is greater than about 0.001.
 1590. The methodof claim 1137, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1160.The method of claim 1137 wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight. whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1161. The method of claim 1137, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1162. The method of claim 1137, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1163. The method of claim 1137, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1164. The method of claim 1137, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1165. The method of claim 1137, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1166. The method of claim 1137, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1167. The method of claim 1137, wherein the producedmixture comprises anon-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1168. The method of claim 1137, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1169. The method of claim1137, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1170. The method of claim 1137,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 1171. The method of claim 1137,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1172. The method ofclaim 1171, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 1173. The method of claim 1137, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1174. The method of claim 1137, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1175. The method of claim1137, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1176. The method of claim1137, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1177. The method of claim 1137, heating the sectioncomprises increasing a permeability of a majority of the section togreater than about 100 millidarcy.
 1178. The method of claim 1137,wherein heating the section comprises substantially uniformly increasinga permeability of a majority of the section.
 1179. The method of claim1137, further comprising controlling the heat to yield greater thanabout 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 1180. The method of claim 1137, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heat sources are disposed in the formation foreach production well.
 1181. The method of claim 1137, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 1182. The method of claim 1137,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1183. A method of treating ahydrocarbon containing formation in situ. comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation; and producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight. when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1184.The method of claim 1183, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 1185. The method of claim 1183,wherein the one or more heat sources comprise electrical heaters. 1186.The method of claim 1183, wherein the one or more heat sources comprisesurface burners.
 1187. The method of claim 1183, wherein the one or moreheat sources comprise flameless distributed combustors.
 1188. The methodof claim 1183, wherein the one or more heat sources comprise naturaldistributed combustors.
 1189. The method of claim 1183, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature or the temperature iscontrolled as a function of pressure.
 1190. The method of claim 1189,wherein controlling the temperature comprises maintaining thetemperature within the selected section within a pyrolysis temperaturerange.
 1191. The method of claim 1183, further comprising controllingthe heat such that an average heating rate of the selected section isless than about 1° C. per day during pyrolysis.
 1192. The method ofclaim 1183, wherein providing heat from the one or more heat sources toat least the portion of formation comprises: heating a selected volume(V) of the hydrocarbon containing formation from the one or more heatsources, wherein the formation has an average heat capacity (C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/dayprovided to the volume is equal to or less than Pwr, wherein Pwr iscalculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is theheating energy/day, h is an average heating rate of the formation, ρ_(B)is formation bulk density, and wherein the heating rate is less thanabout 10° C./day.
 1193. The method of claim 1183, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 1194. The method of claim 1183, wherein providing heat fromthe one or more heat sources comprises heating the selected formationsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1195. The method of claim1183, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1196. The method of claim1183, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1197. The method of claim 1183,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 1198. The method of claim1183, wherein the produced mixture comprises non-condensablehydrocarbons, wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons is less than about 0.15, and wherein theratio of ethene to ethane is greater than about 0.001.
 1199. The methodof claim 1183, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1200. Themethod of claim 1183, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1201. Themethod of claim 1183 wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1202. Themethod of claim 1183, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1203. The method ofclaim 1183, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1204. The method of claim 1183, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1205. The methodof claim 1183, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1206. The method of claim1183, wherein the produced mixture comprises anon-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 1207. The method of claim 1183, whereinthe produced mixture comprises ammonia, and wherein greater than about0.05% by weight of the produced mixture is ammonia.
 1208. The method ofclaim 1183, wherein the produced mixture comprises ammonia, and whereinthe ammonia is used to produce fertilizer.
 1209. The method of claim1183, further comprising controlling a pressure within at least amajority of the selected section of the formation, wherein thecontrolled pressure is at least about 2.0 bar absolute.
 1210. The methodof claim 1183, further comprising controlling formation conditions toproduce a mixture of condensable hydrocarbons and H₂, wherein a partialpressure of H₂ within the mixture is greater than about 0.5 bar. 1211.The method of claim 1211, wherein the partial pressure of H₂ is measuredwhen the mixture is at a production well.
 1212. The method of claim1183, further comprising altering a pressure within the formation toinhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1213. The method of claim 1183 whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1214. The method of claim1183, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1215. The method of claim1183, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1216. The method of claim 1183, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1217. Themethod of claim 1183, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1218. The method of claim 1183, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1219. Themethod of claim 1183, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1220.The method of claim 1183, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1221. The method of claim 1183, further comprisingproviding heat for three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern., and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1222. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; and producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1223. The method of claim 1222,wherein the one or more heat sources comprise at least two heat sources.and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 1224. The method of claim 1222, wherein the one or more heatsources comprise electrical heaters.
 1225. The method of claim 1222,wherein the one or more heat sources comprise surface burners.
 1226. Themethod of claim 1222, wherein the one or more heat sources compriseflameless distributed combustors.
 1227. The method of claim 1222,wherein the one or more heat sources comprise natural distributedcombustors.
 1228. The method of claim 1222, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1229. The method of claim 1228,wherein controlling the temperature comprises maintaining thetemperature within the selected section within a pyrolysis temperaturerange.
 1230. The method of claim 1222, further comprising controllingthe heat such that an average heating rate of the selected section isless than about 1° C. per day during pyrolysis.
 1231. The method ofclaim 1222, wherein providing heat from the one or more heat sources toat least the portion of formation comprises: heating a selected volume(V) of the hydrocarbon containing formation from the one or more heatsources, wherein the formation has an average heat capacity (C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/dayprovided to the volume is equal to or less than Pwr, wherein Pwr iscalculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is theheating energy/day, h is an average heating rate of the formation, ρ_(B)is formation bulk density, and wherein the heating rate is less thanabout 10° C./day.
 1232. The method of claim 1222, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 1233. The method of claim 1222, wherein providing heat fromthe one or more heat sources comprises heating the selected section suchthat a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C).
 1234. The method of claim1222, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1235. The method of claim1222, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1236. The method of claim 1222,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 1237. The method of claim1222, wherein the produced mixture comprises non-condensablehydrocarbons, wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons is less than about 0.15, and wherein theratio of ethene to ethane is greater than about 0.001.
 1238. The methodof claim 1222, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight. when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1239.The method of claim 1222, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1240. The method of claim 1222, wherein the produced mixturecomprises condensable hydrocarbons. and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 1241. The method of claim 1222, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 1242. The method of claim 1222, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 1243. The method of claim 1222, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 1244. The method of claim 1222, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 1245. The method of claim 1222, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1246. The method of claim 1222, wherein the producedmixture comprises anon-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1247. The method of claim 1222, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1248. The method of claim1222, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1249. The method of claim 1222,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 1250. The method of claim 1222,further comprising controlling formation conditions to produce a mixtureof condensable hydrocarbons and H₂, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1251. The method ofclaim 1250, wherein the partial pressure of H₂ is measured when themixture is at a production well.
 1252. The method of claim 1222, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1253. The method of claim 1222, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1254. The method of claim1222, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1255. The method of claim1222, wherein the produced mixture comprises hydrogen and condensablehydrocarbons, the method further comprising hydrogenating a portion ofthe produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1256. The method of claim 1222, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1257. Themethod of claim 1222, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1258. The method of claim 1222, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1259. Themethod of claim 1222, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1260.The method of claim 1222, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1261. The method of claim 1222, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1262. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; and producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons. and wherein lessthan about 1% by weight. when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 1263. The method of claim 1262,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 1264. The method of claim 1262, wherein the one or more heatsources comprise electrical heaters.
 1265. The method of claim 1262,wherein the one or more heat sources comprise surface burners.
 1266. Themethod of claim 1262, wherein the one or more heat sources compriseflameless distributed combustors.
 1267. The method of claim 1262,wherein the one or more heat sources comprise natural distributedcombustors.
 1268. The method of claim 1262, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature. or the temperature iscontrolled as a function of pressure.
 1269. The method of claim 1268,wherein controlling the temperature comprises maintaining thetemperature within the selected section within a pyrolysis temperaturerange.
 1270. The method of claim 1262, further comprising controllingthe heat into such that an average heating rate of the selected sectionis less than about 1° C. per day during pyrolysis.
 1271. The method ofclaim 1262, wherein providing heat from the one or more heat sources toat least the portion of formation comprises: heating a selected volume(V) of the hydrocarbon containing formation from the one or more heatsources, wherein the formation has an average heat capacity (C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/dayprovided to the volume is equal to or less than Pwr, wherein Pwr iscalculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is theheating energy/day, h is an average heating rate of the formation, ρ_(B)is formation bulk density, and wherein the heating rate is less thanabout 10° C./day.
 1272. The method of claim 1262, wherein allowing theheat to transfer comprises transferring heat substantially byconduction.
 1273. The method of claim 1262, wherein providing heat fromthe one or more heat sources comprises heating the selected formationsuch that a thermal conductivity of at least a portion of the selectedsection is greater than about 0.5 W/(m ° C.).
 1274. The method of claim1262, wherein the produced mixture comprises condensable hydrocarbonshaving an API gravity of at least about 25°.
 1275. The method of claim1262, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 1276. The method of claim 1262,wherein the produced mixture comprises non-condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of thenon-condensable hydrocarbons are olefins.
 1277. The method of claim1262, wherein the produced mixture comprises non-condensablehydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratioof ethene to ethane is greater than about 0.001.
 1278. The method ofclaim 1262, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 1279.The method of claim 1262, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 1280. The method of claim 1262, wherein the produced mixturecomprises condensable hydrocarbons, wherein about 5% by weight to about30% by weight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.1281. The method of claim 1262, wherein the produced mixture comprisescondensable hydrocarbons. and wherein greater than about 20% by weightof the condensable hydrocarbons are aromatic compounds.
 1282. The methodof claim 1262, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1283. The method of claim 1262, wherein the produced mixturecomprises condensable hydrocarbons and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1284. The methodof claim 1262, wherein the produced mixture comprises condensablehydrocarbons. and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1285. The method of claim1262, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component. and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1286. The method ofclaim 1262, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1287. The method of claim 1262, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1288.The method of claim 1262, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.1289. The method of claim 1262, further comprising controlling formationconditions to produce a mixture of condensable hydrocarbons and H₂,wherein a partial pressure of H₂within the mixture is greater than about0.5 bar.
 1290. The method of claim 1289, wherein the partial pressure ofH₂ is measured when the mixture is at a production well.
 1291. Themethod of claim 1262, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 1292. The method of claim1262, wherein controlling formation conditions comprises recirculating aportion of hydrogen from the mixture into the formation.
 1293. Themethod of claim 1262, further comprising: providing hydrogen (H₂) to theheated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 1294. Themethod of claim 1262, wherein the produced mixture comprises hydrogenand condensable hydrocarbons, the method further comprisinghydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 1295. The method of claim1262, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 1296. The method of claim 1262, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 1297. The method ofclaim 1262, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 1298. The method of claim 1262, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heat sources are disposed in the formation foreach production well.
 1299. The method of claim 1262, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 1300. The method of claim 1262,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 1301. A method of treating ahydrocarbon containing formation in situ. comprising: raising atemperature of a first section of the formation with one or more heatsources to a first pyrolysis temperature: heating the first section toan upper pyrolysis temperature, wherein heat is supplied to the firstsection at a rate configured to inhibit olefin production; producing afirst mixture from the formation, wherein the first mixture comprisescondensable hydrocarbons and H₂; creating a second mixture from thefirst mixture, wherein the second mixture comprises a higherconcentration of H₂ than the first mixture; raising a temperature of asecond section of the formation with one or more heat sources to asecond pyrolysis temperature; providing a portion of the second mixtureto the second section; heating the second section to an upper pyrolysistemperature, wherein heat is supplied to the second section at a rateconfigured to inhibit olefin production; and producing a third mixturefrom the second section.
 1302. The method of claim 1301, whereincreating the second mixture comprises removing condensable hydrocarbonsfrom the first mixture.
 1303. The method of claim 1301, wherein creatingthe second mixture comprises removing water from the first mixture.1304. The method of claim 1301, wherein creating the second mixturecomprises removing carbon dioxide from the first mixture.
 1305. Themethod of claim 1301, wherein the first pyrolysis temperature is greaterthan about 270° C.
 1306. The method of claim 1301, wherein the secondpyrolysis temperature is greater than about 270° C.
 1307. The method ofclaim 1301, wherein the upper pyrolysis temperature is about 500° C.1308. The method of claim 1301, wherein the one or more heat sourcescomprise at least two heat sources. and wherein superposition of heatfrom at least the two heat sources pyrolyzes at least some hydrocarbonswithin the first or second selected section of the formation.
 1309. Themethod of claim 1301, wherein the one or more heat sources compriseelectrical heaters.
 1310. The method of claim 1301, wherein the one ormore heat sources comprise surface burners.
 1311. The method of claim1301, wherein the one or more heat sources comprise flamelessdistributed combustors.
 1312. The method of claim 1301, wherein the oneor more heat sources comprise natural distributed combustors.
 1313. Themethod of claim 1301, further comprising controlling a pressure and atemperature within at least a majority of the first section and thesecond section of the formation. “herein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 1314. The method of claim 1301, further comprisingcontrolling the heat to the first and second sections such that anaverage heating rate of the first and second sections is less than about1° C. per day during pyrolysis.
 1315. The method of claim 1301, whereinheating the first and the second sections comprises: heating a selectedvolume (V) of the hydrocarbon containing formation from the one or moreheat sources, wherein the formation has an average heat capacity (C,).and wherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation; and wherein heating energy/dayprovided to the volume is equal to or less than Pwr, wherein Pwr iscalculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is theheating energy/day, h is an average heating rate of the formation, ρ_(B)is formation bulk density, and wherein the heating rate is less thanabout 10° C./day.
 1316. The method of claim 1301, wherein heating thefirst and second sections comprises transferring heat substantially byconduction.
 1317. The method of claim 1301, wherein heating the firstand second sections comprises heating the first and second sections suchthat a thermal conductivity of at least a portion of the first andsecond sections is greater than about 0.5 W/(m ° C.).
 1318. The methodof claim 1301, wherein the first or third mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 1319. Themethod of claim 1301, wherein the first or third mixture comprisescondensable hydrocarbons, and wherein about 0.1% by weight to about 15%by weight of the condensable hydrocarbons are olefins.
 1320. The methodof claim 1301, wherein the first or third mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1321. The method of claim 1301, wherein the first or thirdmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1322. The method of claim 1301, wherein thefirst or third mixture comprises condensable hydrocarbons. and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1323. The method of claim 1301,wherein the first or third mixture comprises condensable hydrocarbons.and wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1324. The method ofclaim 1301, wherein the first or third mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds. andwherein the oxygen containing compounds comprise phenols.
 1325. Themethod of claim 1301, wherein the first or third mixture comprisescondensable hydrocarbons. and wherein greater than about 20% by weightof the condensable hydrocarbons are aromatic compounds.
 1326. The methodof claim 1301, wherein the first or third mixture comprises condensablehydrocarbons. and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1327. The method of claim 1301, wherein the first or thirdmixture comprises condensable hydrocarbons, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 1328.The method of claim 1301, wherein the first or third mixture comprisescondensable hydrocarbons, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 1329. Themethod of claim 1301, wherein the first or third mixture comprisesanon-condensable component, and wherein the non-condensable componentcomprises hydrogen, and wherein the hydrogen is greater than about 10%by volume of the non-condensable component and wherein the hydrogen isless than about 80% by volume of the non-condensable component. 1330.The method of claim 1301, wherein the first or third mixture comprisesammonia, and wherein greater than about 0.05% by weight of the producedmixture is ammonia.
 1331. The method of claim 1301, wherein the first orthird mixture comprises ammonia, and wherein the ammonia is used toproduce fertilizer.
 1332. The method of claim 1301, further comprisingcontrolling a pressure within at least a majority of the first or secondsections of the formation, wherein the controlled pressure is at leastabout 2.0 bar absolute.
 1333. The method of claim 1301, furthercomprising controlling formation conditions to produce a mixture ofcondensable hydrocarbons and H₂, wherein a partial pressure of H₂withinthe mixture is greater than about 0.5 bar.
 1334. The method of claim1333, wherein the partial pressure of H₂ within a mixture is measuredwhen the mixture is at a production well.
 1335. The method of claim1301, further comprising altering a pressure within the formation toinhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1336. The method of claim 1301, furthercomprising: providing hydrogen (H₂) to the first or second section tohydrogenate hydrocarbons within the first or second section; and heatinga portion of the first or second section with heat from hydrogenation.1337. The method of claim 1301, further comprising: producing hydrogenand condensable hydrocarbons from the formation; and hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 1338. The method of claim 1301 furthercomprising increasing a permeability of a majority of the first orsecond section to greater than about 100 millidarcy.
 1339. The method ofclaim 1301, further comprising substantially uniformly increasing apermeability of a majority of the first or second section.
 1340. Themethod of claim 1301, wherein the heating is controlled to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 1341. The method of claim 1301 wherein producing thefirst or third mixture comprises producing the first or third mixture ina production well, and wherein at least about 7 heat sources aredisposed in the formation for each production well.
 1342. The method ofclaim 1301, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.1343. The method of claim 1301, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.1344. A method of treating a hydrocarbon containing formation in situ,comprising: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; producing amixture from the formation; and hydrogenating a portion of the producedmixture with H₂ produced from the formation.
 1345. The method of claim1344, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 1346. The method of claim 1344, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 1347. The method of claim 1344, wherein the one ormore heat sources comprise electrical heaters.
 1348. The method of claim1344, wherein the one or more heat sources comprise surface burners.1349. The method of claim 1344, wherein the one or more heat sourcescomprise Blameless distributed combustors.
 1350. The method of claim1344, wherein the one or more heat sources comprise natural distributedcombustors.
 1351. The method of claim 1344, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1352. The method of claim 1344,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1353. The method of claim 1344, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources wherein the formation has anaverage heat capacity (C_(v)), and herein the heating pyrolyzes at leastsome hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1354. The methodof claim 1344, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1355. The method of claim1344, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C).
 1356. The method of claim 1344, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1357. The method of claim 1344, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1358.The method of claim 1344, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1359. The method of claim 1344, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight. when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1360. The method of claim 1344, wherein theproduced mixture comprises condensable hydrocarbons. and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1361. The method of claim 1344,wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight. when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1362. The method ofclaim 1344, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1363. Themethod of claim 1344, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1364. The method ofclaim 1344, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1365. The method of claim 1344, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1366. The methodof claim 1344, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1367. The method of claim1344, wherein the produced mixture comprises anon-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 1368. The method of claim 1344, whereinthe produced mixture comprises ammonia, and wherein greater than about0.05% by weight of the produced mixture is ammonia.
 1369. The method ofclaim 1344, wherein the produced mixture comprises ammonia, and whereinthe ammonia is used to produce fertilizer.
 1370. The method of claim1344, further comprising controlling a pressure within at least amajority of the selected section of the formation, wherein thecontrolled pressure is at least about 2.0 bar absolute.
 1371. The methodof claim 1344, further comprising controlling formation conditions toproduce the mixture, wherein a partial pressure of H₂ within the mixtureis greater than about 0.5 bar.
 1372. The method of claim 1344, whereinthe partial pressure of H2 within the mixture is measured when themixture is at a production well.
 1373. The method of claim 1344, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1374. The method of claim 1344, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1375. The method of claim 1344, whereinallowing the heat to transfer comprises increasing a permeability of amajority of the selected section to greater than about 100 millidarcy.1376. The method of claim 1344, wherein allowing the heat to transfercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 1377. The method of claim 1344,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.1378. The method of claim 1344, wherein producing the mixture comprisesproducing the mixture in a production well. and wherein at least about 7heat sources are disposed in the formation for each production well.1379. The method of claim 1344, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 1380. The method of claim 1344, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 1381. A method of treating a hydrocarboncontaining formation in situ, comprising: heating a first section of theformation; producing H₂ from the first section of formation; heating asecond section of the formation; and recirculating a portion of the H₂from the first section into the second section of the formation toprovide a reducing environment within the second section of theformation.
 1382. The method of claim 1381, wherein heating the firstsection or heating the second section comprises heating with anelectrical heater.
 1383. The method of claim 1381, wherein heating thefirst section or heating the second section comprises heating with asurface burner.
 1384. The method of claim 1381, wherein heating thefirst section or heating the second section comprises heating with aflameless distributed combustor.
 1385. The method of claim 1381, whereinheating the first section or heating the second section comprisesheating with a natural distributed combustor.
 1386. The method of claim1381, further comprising controlling a pressure and a temperature withinat least a majority of the first or second section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 1387. The method ofclaim 1381, further comprising controlling the heat such that an averageheating rate of the first or second section is less than about 1° C. perday during pyrolysis.
 1388. The method of claim 1381, wherein heatingthe first section or heating the second section further comprises:heating a selected volume (V) of the hydrocarbon containing formationfrom the one or more heat sources, wherein the formation has an averageheat capacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/'day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B)is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 1389. The method of claim 1381, whereinheating the first section or heating the second section comprisestransferring heat substantially by conduction.
 1390. The method of claim1381, wherein heating the first section or heating the second sectioncomprises heating the formation such that a thermal conductivity of atleast a portion of the first or second section is greater than about 0.5W/(m ° C.).
 1391. The method of claim 1381, further comprising producinga mixture from the second section, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1392. The method of claim 1381, further comprising producinga mixture from the second section, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1393.The method of claim 1381, further comprising producing a mixture fromthe second section, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1394. The method of claim 1381, further comprising producinga mixture from the second section, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1395. The method of claim 1381 furthercomprising producing a mixture from the second section, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1396. The method of claim 1381,further comprising producing a mixture from the second section, whereinthe produced mixture comprises condensable hydrocarbons, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 1397. The method of claim 1381,further comprising producing a mixture from the second section, whereinthe produced mixture comprises condensable hydrocarbons. and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 1398. The method of claim1381, further comprising producing a mixture from the second section,wherein the produced mixture comprises condensable hydrocarbons, andwherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 1399. The method of claim 1381, furthercomprising producing a mixture from the second section, wherein theproduced mixture comprises condensable hydrocarbons. and wherein lessthan about 5% by weight of the condensable hydrocarbons comprisesmulti-ring aromatics with more than two rings.
 1400. The method of claim1381, further comprising producing a mixture from the second section,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 0.3% by weight of the condensable hydrocarbonsare asphaltenes.
 1401. The method of claim 1381, further comprisingproducing a mixture from the second section, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 1402. The method of claim 1381, further comprisingproducing a mixture from the second section, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1403. The method of claim 1381, furthercomprising producing a mixture from the second section, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1404. The method of claim1381, further comprising producing a mixture from the second section,wherein the produced mixture comprises ammonia, and wherein the ammoniais used to produce fertilizer.
 1405. The method of claim 1381, furthercomprising controlling a pressure within at least a majority of thefirst or second section of the formation, wherein the controlledpressure is at least about 2.0 bar absolute.
 1406. The method of claim1381, further comprising controlling formation conditions to produce amixture of condensable hydrocarbons and H₂, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bar.
 1407. The methodof claim 1406, wherein the partial pressure of H₂ within a mixture ismeasured when the mixture is at a production well.
 1408. The method ofclaim 1381, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1409. The method of claim 1381, furthercomprising: providing hydrogen (H₂) to the second section to hydrogenatehydrocarbons within the section; and heating a portion of the secondsection with heat from hydrogenation.
 1410. The method of claim 1381,further comprising: producing hydrogen and condensable hydrocarbons fromthe formation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1411. Themethod of claim 1381, wherein heating the first section or heating thesecond section comprises increasing a permeability of a majority of thefirst or second section, respectively, to greater than about 100millidarcy.
 1412. The method of claim 1381, wherein heating the firstsection or heating the second section comprises substantially uniformlyincreasing a permeability of a majority of the first or second section,respectively.
 1413. The method of claim 1381, further comprisescontrolling the heating of the first section or controlling the heat ofthe second section to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1414. Themethod of claim 1381, further comprising producing a mixture from theformation in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1415.The method of claim 1381, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1416. The method of claim 1381, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1417. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; producing a mixture from the formation; and controllingformation conditions such that the mixture produced from the formationcomprises condensable hydrocarbons including H₂, wherein the partialpressure of H₂ within the mixture is greater than about 0.5 bar. 1418.The method of claim 1417, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 1419. The method of claim 1417,wherein controlling formation conditions comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 1420. The method of claim 1417, wherein the one or more heatsources comprise electrical heaters.
 1421. The method of claim 1417,wherein the one or more heat sources comprise surface burners.
 1422. Themethod of claim 1417, wherein the one or more heat sources compriseflameless distributed combustors.
 1423. The method of claim 1417,wherein the one or more heat sources comprise natural distributedcombustors.
 1424. The method of claim 1417, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1425. The method of claim 1417,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C per day duringpyrolysis.
 1426. The method of claim 1417, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B)is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1427. The methodof claim 1417, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1428. The method of claim1417, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C).
 1429. The method of claim 1417, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1430. The method of claim 1417, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1431.The method of claim 1417, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1432. The method of claim 1417, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1433. The method of claim 1417, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1434. The method of claim 1417wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight. when calculated on an atomic basisof the condensable hydrocarbons is sulfur.
 1435. The method of claim1417, wherein the produced mixture comprises condensable hydrocarbons,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 1436. The method of claim1417, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 1437. The method of claim 1417,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 1438. Themethod of claim 1417, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 1439. The method of claim1417, wherein the produced mixture comprises condensable hydrocarbons.and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 1440. The method of claim 1417, whereinthe produced mixture comprises anon-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1441. The method of claim 1417, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1442. The method of claim1417, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1443. The method of claim 1417,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 1444. The method of claim 1417,further comprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1445. The method of claim 1417, whereincontrolling formation conditions comprises recirculating a portion ofhydrogen from the mixture into the formation.
 1446. The method of claim1417, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1447. The method of claim1417, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1448. The method of claim 1417, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1449. Themethod of claim 1417, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1450. The method of claim 1417, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1451. Themethod of claim 1417, wherein producing the mixture comprises producingthe mixture in a production well. and wherein at least about 7 heatsources are disposed in the formation for each production well. 1452.The method of claim 1417, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1453. The method of claim 1417, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1454. The method of claim 1417, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1455. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; maintaining a pressure of the selected section aboveatmospheric pressure to increase a partial pressure of H₂, as comparedto the partial pressure of H₂ at atmospheric pressure, in at least amajority of the selected section; and producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 1456. Themethod of claim 1455, wherein the one or more heat sources comprise atleast two heat sources. and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1457. The method of claim 1455,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 1458. The method of claim 1455,wherein the one or more heat sources comprise electrical heaters. 1459.The method of claim 1455, wherein the one or more heat sources comprisesurface burners.
 1460. The method of claim 1455, wherein the one or moreheat sources comprise flameless distributed combustors.
 1461. The methodof claim 1455, wherein the one or more heat sources comprise naturaldistributed combustors.
 1462. The method of claim 1455, furthercomprising controlling the pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1463. The method of claim 1455,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1464. The method of claim 1455, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1465. The methodof claim 1455, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1466. The method of claim1455, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C).
 1467. The method of claim 1455, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1468.The method of claim 1455, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1469. The method of claim 1455, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1470. The method of claim 1455, wherein theproduced mixture comprises condensable hydrocarbons. and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1471. The method of claim 1455wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1472. The method ofclaim 1455, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1473. Themethod of claim 1455, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1474. The method ofclaim 1455, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1475. The method of claim 1455, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1476. The methodof claim 1455, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1477. The method of claim1455, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1478. The method ofclaim 1455, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1479. The method of claim 1455, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1480.The method of claim 1455, further comprising controlling the pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.1481. The method of claim 1455, further comprising increasing thepressure of the selected section, to an upper limit of about 21 barabsolute, to increase an amount of non-condensable hydrocarbons producedfrom the formation.
 1482. The method of claim 1455, further comprisingdecreasing pressure of the selected section. to a lower limit of aboutatmospheric pressure, to increase an amount of condensable hydrocarbonsproduced from the formation.
 1483. The method of claim 1455, wherein thepartial pressure comprises a partial pressure based on propertiesmeasured at a production well.
 1484. The method of claim 1455, furthercomprising altering the pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1485. The method of claim 1455, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1486. The method ofclaim 1455, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1487. The method ofclaim 1455, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1488. The method of claim 1455, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1489. Themethod of claim 1455, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1490. The method of claim 1455, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1491. Themethod of claim 1455, wherein producing the mixture comprises producingthe mixture in a production well. and wherein at least about 7 heatsources are disposed in the formation for each production well. 1492.The method of claim 1455, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1493. The method of claim 1455, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1494. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation: allowing the heat totransfer from the one or more heat sources to a selected section of theformation; providing H₂ to the formation to produce a reducingenvironment in at least some of the formation; producing a mixture fromthe formation.
 1495. The method of claim 1494, wherein the one or moreheat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.1496. The method of claim 1494, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 1497. The method of claim 1494, further comprising separating aportion of hydrogen within the mixture and recirculating the portioninto the formation.
 1498. The method of claim 1494, wherein the one ormore heat sources comprise electrical heaters.
 1499. The method of claim1494, wherein the one or more heat sources comprise surface burners.1500. The method of claim 1494, wherein the one or more heat sourcescomprise flameless distributed combustors.
 1501. The method of claim1494, wherein the one or more heat sources comprise natural distributedcombustors.
 1502. The method of claim 1494, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1503. The method of claim 1494,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1504. The method of claim 1494, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1505. The methodof claim 1494, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1506. The method of claim1494, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1507. The method of claim 1494, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1508. The method of claim 1494, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1509.The method of claim 1494, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1510. The method of claim 1494, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1511. The method of claim 1494, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1512. The method of claim 1494wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight. when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1513. The method ofclaim 1494, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1514. Themethod of claim 1494, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1515. The method ofclaim 1494, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1516. The method of claim 1494, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1517. The methodof claim 1494, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1518. The method of claim1494, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1519. The method ofclaim 1494, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1520. The method of claim 1494, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1521.The method of claim 1494, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.1522. The method of claim 1494, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1523. The method ofclaim 1494, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1524. The method ofclaim 1494, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1525. The method of claim 1494, whereinproviding hydrogen (H₂) to the formation further comprises:hydrogenating hydrocarbons within the section; and heating a portion ofthe section with heat from hydrogenation.
 1526. The method of claim1494, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1527. The method of claim 1494, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1528. Themethod of claim 1494, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1529. The method of claim 1494, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1530. Themethod of claim 1494 wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1531.The method of claim 1494, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1532. The method of claim 1494, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units. 1533 . A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation: allowing the heat totransfer from the one or more heat sources to a selected section of theformation; providing H₂ to the selected section to hydrogenatehydrocarbons within the selected section and to heat a portion of thesection with heat from the hydrogenation; and controlling heating of theselected section by controlling amounts of H₂ provided to the selectedsection.
 1534. The method of claim 1533, wherein the one or more heatsources comprise at least two heat sources. and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 1535. Themethod of claim 1533, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 1536.The method of claim 1533, wherein the one or more heat sources compriseelectrical heaters.
 1537. The method of claim 1533, wherein the one ormore heat sources comprise surface burners.
 1538. The method of claim1533, wherein the one or more heat sources comprise flamelessdistributed combustors.
 1539. The method of claim 1533, wherein the oneor more heat sources comprise natural distributed combustors.
 1540. Themethod of claim 1533, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1541. The method of claim 1533, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 1542. The method of claim 1533,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.1543. The method of claim 1533, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 1544. Themethod of claim 1533, wherein providing heat from the one or more heatsources comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1545. The method of claim 1533, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons having an API gravity of atleast about 25°.
 1546. The method of claim 1533, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1547.The method of claim 1533, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.1548. The method of claim 1533, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 1% by weight, when calculatedon an atomic basis; of the condensable hydrocarbons is nitrogen. 1549.The method of claim 1533, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1550. Themethod of claim 1533, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1551. Themethod of claim 1533, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1552. Themethod of claim 1533, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons. and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1553. The method ofclaim 1533, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 1554. Themethod of claim 1533, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 1555. The method of claim1533, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 1556. The method of claim 1533, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1557. The method of claim 1533, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 1558. The method of claim1533, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 1559. The method of claim 1533, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bar absolute.
 1560. The method of claim 1533, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bar.
 1561. The method of claim 1560, wherein thepartial pressure of H₂ within the mixture is measured when the mixtureis at a production well.
 1562. The method of claim 1533, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1563. The method of claim 1533, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from a produced mixture into the formation.
 1564. The methodof claim 1533, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1565. The method of claim 1533, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1566. Themethod of claim 1533, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1567. The method of claim 1533, wherein the heating iscontrolled of claim 1533, further comprising producing a mixture in aproduction well, and wherein at least about 7 heat sources are disposedin the formation for each production well.
 1568. The method of claim1533, further comprising providing heat from three or more heat sourcesto at least a portion of the formation, wherein three or more of theheat sources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1569.The method of claim 1533, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1570. An in situmethod for producing H₂ from a hydrocarbon containing formation,comprising: providing heat from one or more heat sources to at least aportion of the formation. allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; and producinga mixture from the formation, wherein a H₂ partial pressure within themixture is greater than about 0.5 bar.
 1571. The method of claim 1570,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 1572. The method of claim 1570, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 1573. The method of claim 1570, wherein the one ormore heat sources comprise electrical heaters.
 1574. The method of claim1570, wherein the one or more heat sources comprise surface burners.1575. The method of claim 1570, wherein the one or more heat sourcescomprise flameless distributed combustors.
 1576. The method of claim1570, wherein the one or more heat sources comprise natural distributedcombustors.
 1577. The method of claim 1570, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1578. The method of claim 1570,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1579. The method of claim 1570, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B)is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1580. The methodof claim 1570, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1581. The method of claim1570, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1582. The method of claim 1570, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1583. The method of claim 1570, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1584.The method of claim 1570, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1585. The method of claim 1570, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight. when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1586. The method of claim 1570, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1587. The method of claim 1570,wherein the produced mixture comprises condensable hydrocarbons. andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1588. The method ofclaim 1570, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1589. Themethod of claim 1570, wherein the produced mixture comprises condensablehydrocarbons. and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1590. The method ofclaim 1570, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1591. The method of claim 1570, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1592. The methodof claim 1570, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1592. The method of claim1570, wherein the produced mixture comprises anon-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 1594. The method of claim 1570, whereinthe produced mixture comprises ammonia, and wherein greater than about0.05% by weight of the produced mixture is ammonia.
 1595. The method ofclaim 1570, wherein the produced mixture comprises ammonia, and whereinthe ammonia is used to produce fertilizer.
 1596. The method of claim1570, further comprising controlling a pressure within at least amajority of the selected section of the formation, wherein thecontrolled pressure is at least about 2.0 bar absolute.
 1597. The methodof claim 1570, further comprising altering a pressure within theformation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 1598. The method of claim1570, further comprising recirculating a portion of the hydrogen withinthe mixture into the formation.
 1599. The method of claim 1570, furthercomprising condensing a hydrocarbon component from the produced mixtureand hydrogenating the condensed hydrocarbons with a portion of thehydrogen.
 1600. The method of claim 1570, further comprising: providinghydrogen (H₂) to the heated section to hydrogenate hydrocarbons withinthe section; and heating a portion of the section with heat fromhydrogenation.
 1601. The method of claim 1570, wherein allowing the heatto transfer comprises increasing a permeability of a majority of theselected section to greater than about 100 millidarcy.
 1602. The methodof claim 1570, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1603. The method of claim 1570, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1604. Themethod of claim 1570, wherein producing the mixture comprises producingthe mixture in a production well. and wherein at least about 7 heatsources are disposed in the formation for each production well. 1605.The method of claim 1570, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1606. The method of claim 1570, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1607. The method of claim 1570, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1608. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; wherein the selected section has been selected for heatingusing an atomic hydrogen weight percentage of at least a portion ofhydrocarbons in the selected section, and wherein at least the portionof the hydrocarbons in the selected section comprises an atomic hydrogenweight percentage, when measured on a dry, ash-free basis, of greaterthan about 4.0%; and producing a mixture from the formation.
 1609. Themethod of claim 1608, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1610. The method of claim 1608,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 1611. The method of claim 1608,wherein the one or more heat sources comprise electrical heaters. 1612.The method of claim 1608, wherein the one or more heat sources comprisesurface burners.
 1613. The method of claim 1608, wherein the one or moreheat sources comprise flameless distributed combustors.
 1614. The methodof claim 1608, wherein the one or more heat sources comprise naturaldistributed combustors.
 1615. The method of claim 1608, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1616. The method of claim 1608,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1617. The method of claim 1608, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1618. The methodof claim 1608, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1619. The method of claim1608, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1620. The method of claim 1608, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1621. The method of claim 1608, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1622.The method of claim 1608, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1623. The method of claim 1608, wherein the produced mixturecomprises condensable hydrocarbons. and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1624. The method of claim 1608, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1625. The method of claim 1608,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1626. The method ofclaim 1608, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1627. Themethod of claim 1608, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1628. The method ofclaim 1608, wherein the produced mixture comprises condensablehydrocarbons. and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1629. The method of claim 1608, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1630. The methodof claim 1608, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1631. The method of claim1608, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1632. The method ofclaim 1608, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1633. The method of claim 1608, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1634.The method of claim 1608, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.1635. The method of claim 1608, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1636. The method ofclaim 1635, wherein the partial pressure of H2 within the mixture ismeasured when the mixture is at a production well.
 1637. The method ofclaim 1608, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1638. The method of claim 1608, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1639. The method ofclaim 1608, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1640. The method ofclaim 1608, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1641. The method of claim 1608, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1642. Themethod of claim 1608, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section. 1643 . The method of claim 1608, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1644. Themethod of claim 1608, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1645.The method of claim 1608, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1646. The method of claim 1608, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1647. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; wherein at least some hydrocarbons within the selectedsection have an initial atomic hydrogen weight percentage of greaterthan about 4.0%; and producing a mixture from the formation.
 1648. Themethod of claim 1647, wherein the one or more heat sources comprise atleast two heat sources. and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1649. The method of claim 1647,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 1650. The method of claim 1647,wherein the one or more heat sources comprise electrical heaters. 1651.The method of claim 1647, wherein the one or more heat sources comprisesurface burners.
 1652. The method of claim 1647, wherein the one or moreheat sources comprise flameless distributed combustors.
 1653. The methodof claim 1647, wherein the one or more heat sources comprise naturaldistributed combustors.
 1654. The method of claim 1647, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature. or the temperature iscontrolled as a function of pressure.
 1655. The method of claim 1647,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1656. The method of claim 1647, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B)is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1657. The methodof claim 1647, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1658. The method of claim1647, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1659. The method of claim 1647, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1660. The method of claim 1647, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the. condensable hydrocarbons are olefins. 1661.The method of claim 1647, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1662. The method of claim 1647, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1663. The method of claim 1647, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1664. The method of claim 1647,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1665. The method ofclaim 1647, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1666. Themethod of claim 1647, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1667. The method ofclaim 1647, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1668. The method of claim 1647, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1669. The methodof claim 1647, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1670. The method of claim1647, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1671. The method ofclaim 1647, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1672. The method of claim 1647, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1673.The method of claim 1647, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.1674. The method of claim 1647, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1675. The method ofclaim 1674, wherein the partial pressure of H2 within the mixture ismeasured when the mixture is at a production well.
 1676. The method ofclaim 1647, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1677. The method of claim 1647, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1678. The method ofclaim 1647, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1679. The method ofclaim 1647, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1680. The method of claim 1647, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1681. Themethod of claim 1647, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1682. The method of claim 1647, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1683. Themethod of claim 1647, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1684.The method of claim 1647, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1685. The method of claim 1647, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1686. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; wherein the selected section has been selected for heatingusing vitrinite reflectance of at least some hydrocarbons in theselected section, and wherein at least a portion of the hydrocarbons inthe selected section comprises a vitrinite reflectance of greater thanabout 0.3%; wherein at least a portion of the hydrocarbons in theselected section comprises a vitrinite reflectance of less than about4.5%; and producing a mixture from the formation.
 1687. The method ofclaim 1686, wherein the one or more heat sources comprise at least twoheat sources. and wherein superposition of heat from at least the twoheat sources pyrolyzes at least some hydrocarbons within the selectedsection of the formation.
 1688. The method of claim 1686, furthercomprising maintaining a temperature within the selected section withina pyrolysis temperature.
 1689. The method of claim 1686 wherein thevitrinite reflectance of at least the portion of hydrocarbons within theselected section is between about 0.47% and about 1.5% such that amajority of the produced mixture comprises condensable hydrocarbons.1690. The method of claim 1686, wherein the vitrinite reflectance of atleast the portion of hydrocarbons within the selected section is betweenabout 1.4% and about 4.2% such that a majority of the produced mixturecomprises non-condensable hydrocarbons.
 1691. The method of claim 1686,wherein the one or more heat sources comprise electrical heaters. 1692.The method of claim 1686, wherein the one or more heat sources comprisesurface burners.
 1693. The method of claim 1686, wherein the one or moreheat sources comprise flameless distributed combustors.
 1694. The methodof claim 1686, wherein the one or more heat sources comprise naturaldistributed combustors.
 1695. The method of claim 1686, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1696. The method of claim 1686,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C per day duringpyrolysis.
 1697. The method of claim 1686, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation. andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1698. The methodof claim 1686, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1699. The method of claim1686, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1700. The method of claim 1686, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1701. The method of claim 1686, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1702.The method of claim 1686, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1703. The method of claim 1686, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1704. The method of claim 1686, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1705. The method of claim 1686,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1706. The method ofclaim 1686 wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1707. Themethod of claim 1686, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1708. The method ofclaim 1686, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1709. The method of claim 1686, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1710. The methodof claim 1686, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1711. The method of claim1686, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1712. The method ofclaim 1686, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1713. The method of claim 1686, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1714.The method of claim 1686, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.1715. The method of claim 1686, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1716. The method ofclaim 1715, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1717. The method ofclaim 1686, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1718. The method of claim 1686, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1719. The method ofclaim 1686, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1720. The method ofclaim 1686, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1721. The method of claim 1686, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1722. Themethod of claim 1686, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1723. The method of claim 1686, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1724. Themethod of claim 1686, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1725.The method of claim 1686, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1726. The method of claim 1686, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1727. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; wherein the selected section has been selected for heatingusing a total organic matter weight percentage of at least a portion ofthe selected section, and wherein at least the portion of the selectedsection comprises a total organic matter weight percentage. of at leastabout 5.0%; and producing a mixture from the formation.
 1728. The methodof claim 1727, wherein the one or more heat sources comprise at leasttwo heat sources, and wherein superposition of heat from at least thetwo heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1729. The method of claim 1727,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 1730. The method of claim 1727,wherein the one or more heat sources comprise electrical heaters. 1731.The method of claim 1727, wherein the one or more heat sources comprisesurface burners.
 1732. The method of claim 1727, wherein the one or moreheat sources comprise flameless distributed combustors.
 1733. The methodof claim 1727, wherein the one or more heat sources comprise naturaldistributed combustors.
 1734. The method of claim 1727, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature. or the temperature iscontrolled as a function of pressure.
 1735. The method of claim 1727,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1736. The method of claim 1727, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1737. The methodof claim 1727, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1738. The method of claim1727, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1739. The method of claim 1727, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1740. The method of claim 1727, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1741.The method of claim 1727, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1742. The method of claim 1727, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1743. The method of claim 1727, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1744. The method of claim 1727,wherein the produced mixture comprises condensable hydrocarbons andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1745. The method ofclaim 1727, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1746. Themethod of claim 1727, wherein the produced mixture comprises condensablehydrocarbons. and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1747. The method ofclaim 1727, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1748. The method of claim 1727, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1749. The methodof claim 1727, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1750. The method of claim1727, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1751. The method ofclaim 1727, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1752. The method of claim 1727, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1753.The method of claim 1727, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.1754. The method of claim 1727, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1755. The method ofclaim 1754, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1756. The method ofclaim 1727, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1757. The method of claim 1727, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1758. The method ofclaim 1727, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1759. The method ofclaim 1727, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1760. The method of claim 1727, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1761. Themethod of claim 1727, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1762. The method of claim 1727, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1763. Themethod of claim 1727, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1764.The method of claim 1727, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1765. The method of claim 1727, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1766. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; wherein at least some hydrocarbons within the selectedsection have an initial total organic matter weight percentage of atleast about 5.0%; and producing a mixture from the formation.
 1767. Themethod of claim 1766, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1768. The method of claim 1766,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 1769. The method of claim 1766,wherein the one or more heat sources comprise electrical heaters. 1770.The method of claim 1766, wherein the one or more heat sources comprisesurface burners.
 1771. The method of claim 1766, wherein the one or moreheat sources comprise flameless distributed combustors.
 1772. The methodof claim 1766, wherein the one or more heat sources comprise naturaldistributed combustors.
 1773. The method of claim 1766, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1774. The method of claim 1766,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1775. The method of claim 1766, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1776. The methodof claim 1766, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1777. The method of claim1766, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1778. The method of claim 1766, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1779. The method of claim 1766, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1780.The method of claim 1766, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1781. The method of claim 1766, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1782. The method of claim 1766, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1781. The method of claim 1766,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1784. The method ofclaim 1766, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1785. Themethod of claim 1766, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1786. The method ofclaim 1766, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1787. The method of claim 1766, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1788. The methodof claim 1766, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1789. The method of claim1766, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1790. The method ofclaim 1766, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1791. The method of claim 1766, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1792.The method of claim 1766, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.1793. The method of claim 1766, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1794. The method ofclaim 1793, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1795. The method ofclaim 1766, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1796. The method of claim 1766, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1797. The method ofclaim 1766, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1798. The method ofclaim 1766, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1799. The method of claim 1766, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1800. Themethod of claim 1766, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1801. The method of claim 1766, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1802. Themethod of claim 1766, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1803.The method of claim 1766, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1804. The method of claim 1766, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1805. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation, allowing the heat totransfer from the one or more heat sources to a selected section of theformation; wherein the selected section has been selected for heatingusing an atomic oxygen weight percentage of at least a portion ofhydrocarbons in the selected section, and wherein at least a portion ofthe hydrocarbons in the selected section comprises an atomic oxygenweight percentage of less than about 15% when measured on a dry, ashfree basis; and producing a mixture from the formation.
 1806. The methodof claim 1805, wherein the one or more heat sources comprise at leasttwo heat sources, and wherein superposition of heat from at least thetwo heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 1807. The method of claim 1805,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 1808. The method of claim 1805,wherein the one or more heat sources comprise electrical heaters. 1809.The method of claim 1805, wherein the one or more heat sources comprisesurface burners.
 1810. The method of claim 1805, wherein the one or moreheat sources comprise flameless distributed combustors.
 1811. The methodof claim 1805, wherein the one or more heat sources comprise naturaldistributed combustors.
 1812. The method of claim 1805, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1813. The method of claim 1805,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1814. The method of claim 1805, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1815. The methodof claim 1805, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1816. The method of claim1805, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1817. The method of claim 1805, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1818. The method of claim 1805, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1819.The method of claim 1805, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1820. The method of claim 1805, wherein the produced mixturecomprises condensable hydrocarbons and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1821. The method of claim 1805, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1822. The method of claim 1805,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1823. The method ofclaim 1805, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1824. Themethod of claim 1805, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1825. The method ofclaim 1805, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1826. The method of claim 1805, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1827. The methodof claim 1805, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1828. The method of claim1805, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1829. The method ofclaim 1805, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1830. The method of claim 1805, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1831.The method of claim 1805, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.1832. The method of claim 1805, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1833. The method ofclaim 1832, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1834. The method ofclaim 1805, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1835. The method of claim 1805, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1836. The method ofclaim 1805, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1837. The method ofclaim 1805, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1838. The method of claim 1805, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1839. Themethod of claim 1805, wherein allowing the heat to transfer furthercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 1840. The method of claim 1805,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.1841. The method of claim 1805, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.1842. The method of claim 1805, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 1843. The method of claim 1805, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 1844. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heat sources to a selected section of the formation; allowing theheat to transfer from the one or more heat sources to the selectedsection of the formation to pyrolyze hydrocarbon within the selectedsection; wherein at least some hydrocarbons within the selected sectionhave an initial atomic oxygen weight percentage of less than about 15%;and producing a mixture from the formation.
 1845. The method of claim1844, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 1846. The method of claim 1844, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range
 1847. The method of claim 1844, wherein the one ormore heat sources comprise electrical heaters.
 1848. The method of claim1844, wherein the one or more heat sources comprise surface burners.1849. The method of claim 1844, wherein the one or more heat sourcescomprise flameless distributed combustors.
 1850. The method of claim1844, wherein the one or more heat sources comprise natural distributedcombustors.
 1851. The method of claim 1844, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1852. The method of claim 1844,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1853. The method of claim 1844, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1854. The methodof claim 1844, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1855. The method of claim1844, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1856. The method of claim 1844, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1857. The method of claim 1844, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1858.The method of claim 1844, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1859. The method of claim 1844, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1860. The method of claim 1844, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1861. The method of claim 1844,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight when calculated on an atomic basis,of the condensable hydrocarbons is sulfur.
 1862. The method of claim1844, wherein the produced mixture comprises condensable hydrocarbons,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 1863. The method of claim1844, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 1864. The method of claim 1844,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 1865. Themethod of claim 1844, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 1866. The method of claim1844, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 1867. The method of claim 1844, whereinthe produced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 1868. The method of claim 1844, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 1869. The method of claim1844, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 1870. The method of claim 1844,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 1871. The method of claim 1844,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 1872. The method of claim 1871, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 1873. The method of claim 1844, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 1874. The method of claim 1844, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 1875. The method of claim 1844, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 1876. The method of claim 1844, furthercomprising: producing hydrogen and condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 1877. Themethod of claim 1844, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the selected section togreater than about 100 millidarcy.
 1878. The method of claim 1844,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the selected section. 1879.The method of claim 1844, further comprising controlling the heat toyield greater than about 60% by weight of condensable hydrocarbons, asmeasured by the Fischer Assay.
 1880. The method of claim 1844, whereinproducing the mixture comprises producing the mixture in a productionwell, and wherein at least about 7 heat sources are disposed in theformation for each production well.
 1881. The method of claim 1844,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 1882.The method of claim 1844, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 1883. A methodof treating a hydrocarbon containing formation in situ comprising:providing heat from one or more heat sources to at least a portion ofthe formation; allowing the heat to transfer from the one or more heatsources to a selected section of the formation; wherein the selectedsection has been selected for heating using an atomic hydrogen to carbonratio of at least a portion of hydrocarbons in the selected section,wherein at least a portion of the hydrocarbons in the selected sectioncomprises an atomic hydrogen to carbon ratio greater than about 0.70,and wherein the atomic hydrogen to carbon ratio is less than about 1.65;and producing a mixture from the formation.
 1884. The method of claim1883, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 1885. The method of claim 1883, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 1886. The method of claim 1883, wherein the one ormore heat sources comprise electrical heaters.
 1887. The method of claim1883, wherein the one or more heat sources comprise surface burners.1888. The method of claim 1883, wherein the one or more heat sourcescomprise flameless distributed combustors.
 1889. The method of claim1883, wherein the one or more heat sources comprise natural distributedcombustors.
 1890. The method of claim 1883, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1891. The method of claim 1883,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1892. The method of claim 1883, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1893. The methodof claim 1883, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1894. The method of claim1883, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1895. The method of claim 1883, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1896. The method of claim 1883, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1897.The method of claim 1883, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1898. The method of claim 1883, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1899. The method of claim 1883, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1900. The method of claim 1883,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1901. The method ofclaim 1883, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1902. Themethod of claim 1883, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1903. The method ofclaim 1883, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1904. The method of claim 1883, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1905. The methodof claim 1883, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1906. The method of claim1883, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1907. The method ofclaim 1883, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1908. The method of claim 1883, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1909.The method of claim 1883, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.1910. The method of claim 1883, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1911. The method ofclaim 1910, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1912. The method ofclaim 1883, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1913. The method of claim 1883, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1914. The method ofclaim 1883, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1915. The method ofclaim 1883, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1916. The method of claim 1883, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1917. Themethod of claim 1883, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1918. The method of claim 1883, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1919. Themethod of claim 1883, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1920.The method of claim 1883, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1921. The method of claim 1883, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1922. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to a selected section of the formation; allowing the heat totransfer from the one or more heat sources to the selected section ofthe formation to pyrolyze hydrocarbons within the selected section;wherein at least some hydrocarbons within the selected section have aninitial atomic hydrogen to carbon ratio greater than about 0.70; whereinthe initial atomic hydrogen to carbon ration is less than about 1.65;and producing a mixture from the formation.
 1923. The method of claim1922, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from at least the two heatsources pyrolyzes at least some hydrocarbons within the selected sectionof the formation.
 1924. The method of claim 1922, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 1925. The method of claim 1922, wherein the one ormore heat sources comprise electrical heaters.
 1926. The method of claim1922, wherein the one or more heat sources comprise surface burners.1927. The method of claim 1922, wherein the one or more heat sourcescomprise flameless distributed combustors.
 1928. The method of claim1922, wherein the one or more heat sources comprise natural distributedcombustors.
 1929. The method of claim 1922, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 1930. The method of claim 1922,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 1931. The method of claim 1922, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 1932. The methodof claim 1922, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 1933. The method of claim1922, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 1934. The method of claim 1922, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 1935. The method of claim 1922, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 1936.The method of claim 1922, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 1937. The method of claim 1922, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 1938. The method of claim 1922, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 1939. The method of claim 1922,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 1940. The method ofclaim 1922, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1941. Themethod of claim 1922, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1942. The method ofclaim 1922, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1943. The method of claim 1922, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1944. The methodof claim 1922, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1945. The method of claim1922, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 1946. The method ofclaim 1922, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.1947. The method of claim 1922, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 1948.The method of claim 1922, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.1949. The method of claim 1922, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 1950. The method ofclaim 1949, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 1951. The method ofclaim 1922, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 1952. The method of claim 1922, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1953. The method ofclaim 1922, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1954. The method ofclaim 1922, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1955. The method of claim 1922, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1956. Themethod of claim 1922, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 1957. The method of claim 1922, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 1958. Themethod of claim 1922, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 1959.The method of claim 1922, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 1960. The method of claim 1922, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 1961. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation: allowing the heat totransfer from the one or more heat sources to a selected section of theformation: wherein the selected section has been selected for heatingusing an atomic oxygen to carbon ratio of at least a portion ofhydrocarbons in the selected section, wherein at least a portion of thehydrocarbons in the selected section comprises an atomic oxygen tocarbon ratio greater than about 0.025, and wherein the atomic oxygen tocarbon ratio of at least a portion of the hydrocarbons in the selectedsection is less than about 0.15 and producing a mixture from theformation.
 1962. The method of claim 1961, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 1963. Themethod of claim 1961, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 1964.The method of claim 1961, wherein the one or more heat sources compriseelectrical heaters.
 1965. The method of claim 1961, wherein the one ormore heat sources comprise surface burners.
 1966. The method of claim1961, wherein the one or more heat sources comprise flamelessdistributed combustors.
 1967. The method of claim 1961, wherein the oneor more heat sources comprise natural distributed combustors.
 1968. Themethod of claim 1961, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.1969. The method of claim 1961, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 1° C. per day during pyrolysis.
 1970. The method of claim 1961,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.1971. The method of claim 1961, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 1972. Themethod of claim 1961, wherein providing heat from the one or more heatsources comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 1973. The method of claim 1961, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 1974. The method of claim 1961, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 1975. The method of claim 1961, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 1976. The method of claim 1961,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 1977. The method ofclaim 1961, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 1978. Themethod of claim 1961, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 1979. Themethod of claim 1961, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 1980. Themethod of claim 1961, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 1981. The method ofclaim 1961, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 1982. The method of claim 1961, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 1983. The methodof claim 1961, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 1984. The method of claim1961, wherein the produced mixture comprises anon-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 1985. The method of claim 1961, whereinthe produced mixture comprises ammonia, and wherein greater than about0.05% by weight of the produced mixture is ammonia.
 1986. The method ofclaim 1961, wherein the produced mixture comprises ammonia, and whereinthe ammonia is used to produce fertilizer.
 1987. The method of claim1961, further comprising controlling a pressure within at least amajority of the selected section of the formation, wherein thecontrolled pressure is at least about 2.0 bar absolute.
 1988. The methodof claim 1961, further comprising controlling formation conditions toproduce the mixture, wherein a partial pressure of H₂ within the mixtureis greater than about 0.5 bar.
 1989. The method of claim 1988, whereinthe partial pressure of H₂ within the mixture is measured when themixture is at a production well.
 1990. The method of claim 1961, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 1991. The method of claim 1961, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 1992. The method ofclaim 1961, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 1993. The method ofclaim 1961, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 1994. The method of claim 1961, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 1995. Themethod of claim 1961, wherein allowing the heat to transfer furthercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 1996. The method of claim 1961,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.1997. The method of claim 1961, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.1998. The method of claim 1961, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 1999. The method of claim 1961, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 2000. A method of treating a hydrocarboncontaining formation in situ, comprising providing heat from one or moreheat sources to a selected section of the formation allowing the heat totransfer from the one or more heat sources to the selected section ofthe formation to pyrolyze hydrocarbons within the selected section;wherein at least some hydrocarbons within the selected section have aninitial atomic oxygen to carbon ratio greater than about 0.025; whereinthe initial atomic oxygen to carbon ratio is less than about 0.15; andproducing a mixture from the formation.
 2001. The method of claim 2000,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 2002. The method of claim 2000, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 2003. The method of claim 2000, wherein the one ormore heat sources comprise electrical heaters.
 2004. The method of claim2000, wherein the one or more heat sources comprise surface burners.2005. The method of claim 2000, wherein the one or more heat sourcescomprise flameless distributed combustors.
 2006. The method of claim2000, wherein the one or more heat sources comprise natural distributedcombustors.
 2007. The method of claim 2000, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2008. The method of claim 2000,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2009. The method of claim 2000, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation: andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2010. The methodof claim 2000, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2011. The method of claim2000, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 2012. The method of claim 2000, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 2013. The method of claim 2000, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2014.The method of claim 2000, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2015. The method of claim 2000, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 2016. The method of claim 2000, wherein theproduced mixture comprises condensable hydrocarbons and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2017. The method of claim 2000,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 2018. The method ofclaim 2000, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2019. Themethod of claim 2000, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2020. The method ofclaim 2000, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2021. The method of claim 2000, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2022. The methodof claim 2000, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2023. The method of claim2000, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2024. The method ofclaim 2000, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2025. The method of claim 2000, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2026.The method of claim 2000, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.2027. The method of claim 2000, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 2028. The method ofclaim 2027, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2029. The method ofclaim 2000, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2030. The method of claim 2000, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2031. The method ofclaim 2000, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 2032. The method ofclaim 2000, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2033. The method of claim 2000, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2034. Themethod of claim 2000, wherein allowing the heat to transfer furthercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 2035. The method of claim 2000,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2036. The method of claim 2000, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.2037. The method of claim 2000, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 2038. The method of claim 2000, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 2039. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation: wherein the selected section has been selected forheating using a moisture content in the selected section, and wherein atleast a portion of the selected section comprises a moisture content ofless than about 15%; and producing a mixture from the formation. 2040.The method of claim 2039, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 2041. The method of claim 2039,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 2042. The method of claim 2039,wherein the one or more heat sources comprise electrical heaters. 2043.The method of claim 2039, wherein the one or more heat sources comprisesurface burners.
 2044. The method of claim 2039, wherein the one or moreheat sources comprise flameless distributed combustors.
 2045. The methodof claim 2039, wherein the one or more heat sources comprise naturaldistributed combustors.
 2046. The method of claim 2039, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2047. The method of claim 2039,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2048. The method of claim 2039, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2049. The methodof claim 2039, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2050. The method of claim2039, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 2051. The method of claim 2039, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 2052. The method of claim 2039, wherein the produced mixturecomprises, condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2053.The method of claim 2039, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2054. The method of claim 2039, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 2055. The method of claim 2039, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2056. The method of claim 2039,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 2057. The method ofclaim 2039, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2058. Themethod of claim 2039, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2059. The method ofclaim 2039, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2060. The method of claim 2039, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2061. The methodof claim 2039, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2062. The method of claim2039, wherein the produced mixture comprises anon-condensable component,wherein the non-condensable component comprises hydrogen, wherein thehydrogen is greater than about 10% by volume of the non-condensablecomponent, and wherein the hydrogen is less than about 80% by volume ofthe non-condensable component.
 2063. The method of claim 2039, whereinthe produced mixture comprises ammonia, and wherein greater than about0.05% by weight of the produced mixture is ammonia.
 2064. The method ofclaim 2039, wherein the produced mixture comprises ammonia and whereinthe ammonia is used to produce fertilizer.
 2065. The method of claim2039, further comprising controlling a pressure within at least amajority of the selected section of the formation, wherein thecontrolled pressure is at least about 2.0 bar absolute.
 2066. The methodof claim 2039, further comprising controlling formation conditions toproduce the mixture, wherein a partial pressure of H₂ within the mixtureis greater than about 0.5 bar.
 2067. The method of claim 2066, whereinthe partial pressure of H₂ within the mixture is measured when themixture is at a production well.
 2068. The method of claim 2039, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 2069. The method of claim 2039, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2070. The method ofclaim 2039, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section, and heating aportion of the section with heat from hydrogenation.
 2071. The method ofclaim 2039, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2072. The method of claim 2039, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2073. Themethod of claim 2039, wherein allowing the heat to transfer furthercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 2074. The method of claim 2039,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2075. The method of claim 2039, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.2076. The method of claim 2039, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 2077. The method of claim 2039, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 2078. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heat sources to a selected section of the formation; allowing theheat to transfer from the one or more heat sources to the selectedsection of the formation; wherein at least a portion of the selectedsection has an initial moisture content of less than about 15%; andproducing a mixture from the formation.
 2079. The method of claim 2078,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 2080. The method of claim 2078, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 2081. The method of claim 2078, wherein the one ormore heat sources comprise electrical heaters.
 2082. The method of claim2078, wherein the one or more heat sources comprise surface burners.2083. The method of claim 2078, wherein the one or more heat sourcescomprise flameless distributed combustors.
 2084. The method of claim2078, wherein the one or more heat sources comprise natural distributedcombustors.
 2085. The method of claim 2078, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2086. The method of claim 2078,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2087. The method of claim 2078, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2088. The methodof claim 2078, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2089. The method of claim2078, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 2090. The method of claim 2078, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 2091. The method of claim 2078, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2092.The method of claim 2078, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2093. The method of claim 2078, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 2094. The method of claim 2078, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2095. The method of claim 2078,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 2096. The method ofclaim 2078, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2097. Themethod of claim 2078, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2098. The method ofclaim 2078, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2099. The method of claim 2078, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2100. The methodof claim 2078, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2101. The method of claim2078, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2102. The method ofclaim 2078, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2103. The method of claim 2078, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2104.The method of claim 2078, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.2105. The method of claim 2078, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 2106. The method ofclaim 2105, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2107. The method ofclaim 2078, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2108. The method of claim 2078, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2109. The method ofclaim 2078, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 2110. The method ofclaim 2078, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2111. The method of claim 2078, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2112. Themethod of claim 2078, wherein allowing the heat to transfer furthercomprises substantially uniformly increasing a permeability of amajority of the selected section.
 2113. The method of claim 2078,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2114. The method of claim 2078, wherein producing the mixture comprisesproducing the mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.2115. The method of claim 2078, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 2116. The method of claim 2078, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 2117. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; wherein the selected section is heated in a reducingenvironment during at least a portion of the time that the selectedsection is being heated; and producing a mixture from the formation.2118. The method of claim 2117, wherein the one or more heat sourcescomprise at least two heat sources, and wherein superposition of heatfrom at least the two heat sources pyrolyzes at least some hydrocarbonswithin the selected section of the formation.
 2119. The method of claim2117, further comprising maintaining a temperature within the selectedsection within a pyrolysis temperature range.
 2120. The method of claim2117, wherein the one or more heat sources comprise electrical heaters.2121. The method of claim 2117, wherein the one or more heat sourcescomprise surface burners.
 2122. The method of claim 2117, wherein theone or more heat sources comprise flameless distributed combustors.2123. The method of claim 2117, wherein the one or more heat sourcescomprise natural distributed combustors.
 2124. The method of claim 2117,further comprising controlling a pressure and a temperature within atleast a majority of the selected section of the formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 2125. The method of claim 2117,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2126. The method of claim 2117, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2127. The methodof claim 2117, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2128. The method of claim2117, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 2129. The method of claim 2117, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 2130. The method of claim 2117, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2131.The method of claim 2117, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2132. The method of claim 2117, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 2133. The method of claim 2117, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2134. The method of claim 2117,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 2135. The method ofclaim 2117, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2136. Themethod of claim 2117, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2137. The method ofclaim 2117, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2138. The method of claim 2117, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2139. The methodof claim 2117, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2140. The method of claim2117, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2141. The method ofclaim 2117, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2142. The method of claim 2117, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2143.The method of claim 2117, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.2144. The method of claim 2117, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 2145. The method ofclaim 2144, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2146. The method ofclaim 2117, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2147. The method of claim 2117, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2148. The method ofclaim 2117, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 2149. The method ofclaim 2117, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2150. The method of claim 2117, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2151. Themethod of claim 2117, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 2152. The method of claim 2117, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 2153. Themethod of claim 2117, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 2154.The method of claim 2117, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 2155. The method of claim 2117, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2156. A method of treating a hydrocarbon containingformation in situ, comprising: heating a first section of the formationto produce a mixture from the formation; heating a second section of theformation; and recirculating a portion of the produced mixture from thefirst section into the second section of the formation to provide areducing environment within the second section of the formation. 2157.The method of claim 2156, further comprising maintaining a temperaturewithin the first section or the second section within a pyrolysistemperature range.
 2158. The method of claim 2156, wherein heating thefirst or the second section comprises heating with an electrical heater.2159. The method of claim 2156, wherein heating the first or the secondsection comprises heating with a surface burner.
 2160. The method ofclaim 2156, wherein heating the first or the second section comprisesheating with a flameless distributed combustor.
 2161. The method ofclaim 2156, wherein heating the first or the second section comprisesheating with a natural distributed combustor.
 2162. The method of claim2156, further comprising controlling a pressure and a temperature withinat least a majority of the first or second section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2163. The method ofclaim 2156, further comprising controlling the heat such that an averageheating rate of the first or the second section is less than about 1° C.per day during pyrolysis.
 2164. The method of claim 2156, whereinheating the first or the second section comprises: heating a selectedvolume (V) of the hydrocarbon containing formation from one or more heatsources, wherein the formation has an average heat capacity (C_(v)), andwherein the heating pyrolyzes at least some hydrocarbons within theselected volume of the formation, and wherein heating energy/dayprovided to the volume is equal to or less than Pwr, wherein Pwr iscalculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is theheating energy/day, h is an average heating rate of the formation,ρ_(B)is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 2165. The method of claim 2156, wherein heatingthe first or the second section comprises transferring heatsubstantially by conduction.
 2166. The method of claim 2156, whereinheating the first or the second section comprises heating the first orthe second section such that a thermal conductivity of at least aportion of the first or the second section is greater than about 0.5W/(m ° C.).
 2167. The method of claim 2156, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 2168. The method of claim 2156, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2169.The method of claim 2156, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2170. The method of claim 2156, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 2171. The method of claim 2156, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2172. The method of claim 2156,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 2173. The method ofclaim 2156, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2174. Themethod of claim 2156, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2175. The method ofclaim 2156, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2176. The method of claim 2156, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2177. The methodof claim 2156, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2178. The method of claim2156, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2179. The method ofclaim 2156, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2180. The method of claim 2156, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2181.The method of claim 2156, further comprising controlling a pressurewithin at least a majority of the first or second section of theformation, wherein the controlled pressure is at least about 2.0 barabsolute.
 2182. The method of claim 2156, further comprising controllingformation conditions to produce the mixture, wherein a partial pressureof H₂ within the mixture is greater than about 0.5 bar.
 2183. The methodof claim 2182, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2184. The method ofclaim 2156, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2185. The method of claim 2156, furthercomprising: providing hydrogen (H₂) to the first or second section tohydrogenate hydrocarbons within the first or second section; and heatinga portion of the first or second section with heat from hydrogenation.2186. The method of claim 2156, further comprising: producing hydrogenand condensable hydrocarbons from the formation; and hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 2187. The method of claim 2156, whereinheating the first or the second section comprises increasing apermeability of a majority of the first or the second section to greaterthan about 100 millidarcy.
 2188. The method of claim 2156, whereinheating the first or the second section comprises substantiallyuniformly increasing a permeability of a majority of the first or thesecond section.
 2189. The method of claim 2156, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 2190. Themethod of claim 2156, wherein producing the mixture comprises producingthe mixture in a production well, and wherein at least about 7 heatsources are disposed in the formation for each production well. 2191.The method of claim 2156, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 2192. The method of claim 2156, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 2193. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; and allowing the heat totransfer from the one or more heat sources to a selected section of theformation such that a permeability of at least a portion of the selectedsection increases to greater than about 100 millidarcy.
 2194. The methodof claim 2193, wherein the one or more heat sources comprise at leasttwo heat sources, and wherein superposition of heat from at least thetwo heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 2195. The method of claim 2193,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 2196. The method of claim 2193,wherein the one or more heat sources comprise electrical heaters. 2197.The method of claim 2193, wherein the one or more heat sources comprisesurface burners.
 2198. The method of claim 2193, wherein the one or moreheat sources comprise flameless distributed combustors.
 2199. The methodof claim 2193, wherein the one or more heat sources comprise naturaldistributed combustors.
 2200. The method of claim 2193, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2201. The method of claim 2193,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2202. The method of claim 2193, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation: andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2203. The methodof claim 2193, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2204. The method of claim2193, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 2205. The method of claim 2193, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.2206. The method of claim 2193, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2207. The method of claim2193, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2208. The method of claim 2193,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2209. The method of claim 2193,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2210. The method of claim 2193,further comprising producing a mixture from the formation wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2211. The method of claim 2193,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2212. The method of claim 2193, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2213.The method of claim 2193, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2214. The method of claim 2193, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2215. The method of claim2193, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2216. The method of claim 2193, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2217. The method of claim 2193, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2218. The method of claim2193, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2219. The method of claim 2193, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bar absolute.
 2220. The method of claim 2193, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bar.
 2221. The method of claim 2220, furthercomprising producing a mixture from the formation, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2222. The method of claim 2193, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2223. The method of claim 2193, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2224. The method of claim 2193, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2225. The method of claim 2193, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2226. The method of claim2193, further comprising increasing a permeability of a majority of theselected section to greater than about 5 Darcy.
 2227. The method ofclaim 2193, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 2228. The method of claim 2193, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 2229. Themethod of claim 2193, further comprising producing a mixture in aproduction well, wherein at least about 7 heat sources are disposed inthe formation for each production well.
 2230. The method of claim 2193,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2231.The method of claim 2193, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2232. A methodof treating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; and allowing the heat to transfer from the one or moreheat sources to a selected section of the formation such that apermeability of a majority of at least a portion of the selected sectionincreases substantially uniformly.
 2233. The method of claim 2232,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 2234. The method of claim 2232, further comprisingmaintaining a temperature within the selected section within a pyrolysistemperature range.
 2235. The method of claim 2232, wherein the one ormore heat sources comprise electrical heaters.
 2236. The method of claim2232, wherein the one or more heat sources comprise surface burners.2237. The method of claim 2232, wherein the one or more heat sourcescomprise flameless distributed combustors.
 2238. The method of claim2232, wherein the one or more heat sources comprise natural distributedcombustors.
 2239. The method of claim 2232, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2240. The method of claim 2232,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2241. The method of claim 2232, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2242. The methodof claim 2232, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2243. The method of claim2232, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 2244. The method of claim 2232, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.2245. The method of claim 2232, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2246. The method of claim2232, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2247. The method of claim 2232,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2248. The method of claim 2232,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2249. The method of claim 2232,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2250. The method of claim 2232,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2251. The method of claim 2232, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2252.The method of claim 2232, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2253. The method of claim 2232, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2254. The method of claim2232, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2255. The method of claim 2232, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2256. The method of claim 2232, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2257. The method of claim2232, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2258. The method of claim 2232, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bar absolute.
 2259. The method of claim 2232, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bar.
 2260. The method of claim 2232, furthercomprising producing a mixture from the formation, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2261. The method of claim 2232, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2262. The method of claim 2232, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2263. The method of claim 2232, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2264. The method of claim 2232, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2265. The method of claim2232, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2266. The method of claim 2232, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 2267. Themethod of claim 2232, further comprising producing a mixture in aproduction well, wherein at least about 7 heat sources are disposed inthe formation for each production well.
 2268. The method of claim 2232,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2269.The method of claim 2232, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2270. A methodof treating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; and allowing the heat to transfer from the one or moreheat sources to a selected section of the formation such that a porosityof a majority of at least a portion of the selected section increasessubstantially uniformly.
 2271. The method of claim 2270, wherein the oneor more heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.2272. The method of claim 2270, further comprising maintaining atemperature within the selected section within a pyrolysis temperaturerange.
 2273. The method of claim 2270, wherein the one or more heatsources comprise electrical heaters.
 2274. The method of claim 2270,wherein the one or more heat sources comprise surface burners.
 2275. Themethod of claim 2270, wherein the one or more heat sources compriseflameless distributed combustors.
 2276. The method of claim 2270,wherein the one or more heat sources comprise natural distributedcombustors.
 2277. The method of claim 2270, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2278. The method of claim 2270,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2279. The method of claim 2270, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2280. The methodof claim 2270, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2281. The method of claim2270, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 2282. The method of claim 2270, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.2283. The method of claim 2270, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2284. The method of claim2270, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2285. The method of claim 2270,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2286. The method of claim 2270,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2287. The method of claim 2270,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2288. The method of claim 2270,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2289. The method of claim 2270, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2290.The method of claim 2270, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2291. The method of claim 2270, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2292. The method of claim2270, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2293. The method of claim 2270, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2294. The method of claim 2270, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2295. The method of claim2270, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2296. The method of claim 2270, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bar absolute.
 2297. The method of claim 2270, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bar.
 2298. The method of claim 2270, furthercomprising producing a mixture from the formation, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2299. The method of claim 2270, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2300. The method of claim 2270, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2301. The method of claim 2270, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2302. The method of claim 2270, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2303. The method of claim2270, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2304. The method of claim 2270, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2305. The method ofclaim 2270, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 2306. The method of claim 2270, further comprisingproducing a mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.2307. The method of claim 2270, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 2308. The method of claim 2270, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 2309. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; and controlling the heat to yield at least about 15%by weight of a total organic carbon content of at least some of thehydrocarbon containing formation into condensable hydrocarbons. 2310.The method of claim 2309, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 2311. The method of claim 2309,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 2312. The method of claim 2309,wherein the one or more heat sources comprise electrical heaters. 2313.The method of claim 2309, wherein the one or more heat sources comprisesurface burners.
 2314. The method of claim 2309, wherein the one or moreheat sources comprise flameless distributed combustors.
 2315. The methodof claim 2309, wherein the one or more heat sources comprise naturaldistributed combustors.
 2316. The method of claim 2309, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2317. The method of claim 2309,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2318. The method of claim 2309, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V), of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2319. The methodof claim 2309, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2320. The method of claim2309, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 3221. The method of claim 2309, further comprising producing amixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.2322. The method of claim 2309, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2323. The method of claim2309, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2324. The method of claim 2309,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2325. The method of claim 2309,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2326. The method of claim 2309,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2327. The method of claim 2309,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2328. The method of claim 2309, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2329.The method of claim 2309, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2330. The method of claim 2309, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2331. The method of claim2309, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2332. The method of claim 2309, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2333. The method of claim 2309, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2334. The method of claim2309, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2335. The method of claim 2309, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bar absolute.
 2336. The method of claim 2309, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bar.
 2337. The method of claim 2309, furthercomprising producing a mixture from the formation, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2338. The method of claim 2309, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2339. The method of claim 2309, further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2340. The method of claim 2309, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2341. The method of claim 2309, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2342. The method of claim2309, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2343. The method of claim 2309, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2344. The method ofclaim 2309, wherein the heating is controlled to yield greater thanabout 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 2345. The method of claim 2309, further comprisingproducing a mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.2346. The method of claim 2309, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 2347. The method of claim 2309, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 2348. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heat sources to at least a portion of the formation, allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; and controlling the heat to yield greater than about60% by weight of condensable hydrocarbons, as measured by the FischerAssay.
 2349. The method of claim 2348, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 2350. Themethod of claim 2348, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 2351.The method of claim 2348, wherein the one or more heat sources compriseelectrical heaters.
 2352. The method of claim 2348, wherein the one ormore heat sources comprise surface burners.
 2353. The method of claim2348, wherein the one or more heat sources comprise flamelessdistributed combustors.
 2354. The method of claim 2348, wherein the oneor more heat sources comprise natural distributed combustors.
 2355. Themethod of claim 2348, further comprising controlling a pressure and atemperature within at least a majority of the selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.2356. The method of claim 2348, further comprising controlling the heatsuch that an average heating rate of the selected section is less thanabout 120 C. per day during pyrolysis.
 2357. The method of claim 2348,wherein providing heat from the one or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from the one or more heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.2358. The method of claim 2348, wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 2359. Themethod of claim 2348, wherein providing heat from the one or more heatsources comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 2360. The method of claim 2348, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons having an API gravity of atleast about 25°.
 2361. The method of claim 2348, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2362.The method of claim 2348, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.2363. The method of claim 2348, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2364.The method of claim 2348, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2365. Themethod of claim 2348, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2366. Themethod of claim 2348, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2367. Themethod of claim 2348, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2368. The method ofclaim 2348, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2369. Themethod of claim 2348, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2370. The method of claim2348, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2371. The method of claim 2348, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2372. The method of claim 2348, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2373. The method of claim2348, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2374. The method of claim 2348 further comprisingcontrolling a pressure within at least a majority of the selectedsection of the formation, wherein the controlled pressure is at leastabout 2.0 bar absolute.
 2375. The method of claim 2348, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bar.
 2376. The method of claim 2348, furthercomprising producing a mixture from the formation, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2377. The method of claim 2348, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2378. The method of claim 2348 further comprising producing amixture from the formation and controlling formation conditions byrecirculating a portion of hydrogen from the mixture into the formation.2379. The method of claim 2348, further comprising: providing hydrogen(H₂) to the heated section to hydrogenate hydrocarbons within thesection; and heating a portion of the section with heat fromhydrogenation.
 2380. The method of claim 2348, further comprising:producing hydrogen and condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2381. The method of claim2348, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2382. The method of claim 2348, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2383. The method ofclaim 2348, further comprising producing a mixture in a production well,and wherein at least about 7 heat sources are disposed in the formationfor each production well.
 2384. The method of claim 2348, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, and wherein the unitof heat sources comprises a triangular pattern.
 2385. The method ofclaim 2348, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,wherein the unit of heat sources comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 2386. A method oftreating a hydrocarbon containing formation in situ, comprising: heatinga first section of the formation to pyrolyze at least some hydrocarbonsin the first section and produce a first mixture from the formation;heating a second section of the formation to pyrolyze at least somehydrocarbons in the second section and produce a second mixture from theformation; and leaving an unpyrolyzed section between the first sectionand the second section to inhibit subsidence of the formation.
 2387. Themethod of claim 2386, further comprising maintaining a temperaturewithin the first section or the second section within a pyrolysistemperature range.
 2388. The method of claim 2386, wherein heating thefirst section or heating the second section comprises heating with anelectrical heater.
 2389. The method of claim 2386, wherein heating thefirst section or heating the second section comprises heating with asurface burner.
 2390. The method of claim 2386, wherein heating thefirst section or heating the second section comprises heating with aflameless distributed combustor.
 2391. The method of claim 2386, whereinheating the first section or heating the second section comprisesheating with a natural distributed combustor.
 2392. The method of claim2386, further comprising controlling a pressure and a temperature withinat least a majority of the first or second section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2393. The method ofclaim 2386, further comprising controlling the heat such that an averageheating rate of the first or second section is less than about 1° C. perday during pyrolysis.
 2394. The method of claim 2386, wherein heatingthe first section or heating the second section comprises: heating aselected volume (V) of the hydrocarbon containing formation from one ormore heat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 2395. The method of claim 2386, wherein heatingthe first section or heating the second section comprises transferringheat substantially by conduction.
 2396. The method of claim 2386,wherein heating the first section or heating the second sectioncomprises heating the formation such that a thermal conductivity of atleast a portion of the first or second section, respectively, is greaterthan about 0.5 W/(m ° C.).
 2397. The method of claim 2386, wherein thefirst or second mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2398. The method of claim 2386, whereinthe first or second mixture comprises condensable hydrocarbons, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2399. The method of claim 2386, wherein thefirst or second mixture comprises non-condensable hydrocarbons, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2400. The method ofclaim 2386 wherein the first or second mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2401.The method of claim 2386, wherein the first or second mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2402. The method of claim 2386, wherein the first or secondmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2403. The method of claim 2386, wherein thefirst or second mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 2404. The method of claim2386, wherein the first or second mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2405. The method ofclaim 2386, wherein the first or second mixture comprises condensablehydrocarbons and wherein less than about 5% by weight of the condensablehydrocarbons comprises multi-ring aromatics with more than two rings.2406. The method of claim 2386, wherein the first or second mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2407. The methodof claim 2386, wherein the first or second mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2408. The method of claim2386, wherein the first or second mixture comprises a non-condensablecomponent, and wherein the non-condensable component comprises hydrogen,and wherein the hydrogen is greater than about 10% by volume of thenon-condensable component and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2409. The method ofclaim 2386, wherein the first or second mixture comprises ammonia, andwherein greater than about 0.05% by weight of the first or secondmixture is ammonia.
 2410. The method of claim 2386, wherein the first orsecond mixture comprises ammonia, and wherein the ammonia is used toproduce fertilizer.
 2411. The method of claim 2386, further comprisingcontrolling a pressure within at least a majority of the first or secondsection of the formation, wherein the controlled pressure is at leastabout 2.0 bar absolute.
 2412. The method of claim 2386, furthercomprising controlling formation conditions to produce the first orsecond mixture, wherein a partial pressure of H₂ within the first orsecond mixture is greater than about 0.5 bar.
 2413. The method of claim2386, wherein a partial pressure of H₂ within the first or secondmixture is measured when the first or second mixture is at a productionwell.
 2414. The method of claim 2386, further comprising altering apressure within the formation to inhibit production of hydrocarbons fromthe formation having carbon numbers greater than about
 25. 2415. Themethod of claim 2386, further comprising controlling formationconditions by recirculating a portion of hydrogen from the first orsecond mixture into the formation.
 2416. The method of claim 2386,further comprising: providing hydrogen (H₂) to the first or secondsection to hydrogenate hydrocarbons within the first or second section,respectively; and heating a portion of the first or second section,respectively, with heat from hydrogenation.
 2417. The method of claim2386, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2418. The method of claim 2386, wherein heating thefirst section or heating the second section comprises increasing apermeability of a majority of the first or second section, respectively,to greater than about 100 millidarcy.
 2419. The method of claim 2386,wherein heating the first section or heating the second sectioncomprises substantially uniformly increasing a permeability of amajority of the first or second section, respectively.
 2420. The methodof claim 2386, further comprising controlling heating of the first orsecond section to yield greater than about 60% by weight of condensablehydrocarbons, as measured by the Fischer Assay, from the first or secondsection, respectively.
 2421. The method of claim 2386, wherein producingthe first or second mixture comprises producing the first or secondmixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 2422. The methodof claim 2386, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.2423. The method of claim 2386, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.2424. A method of treating a hydrocarbon containing formation in situ,comprising: providing heat from one or more heat sources to at least aportion of the formation; allowing the heat to transfer from the one ormore heat sources to a selected section of the formation; and producinga mixture from the formation through one or more production wells,wherein the heating is controlled such that the mixture can be producedfrom the formation as a vapor, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 2425. The methodof claim 2424, wherein the one or more heat sources comprise at leasttwo heat sources, and wherein superposition of heat from at least thetwo heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 2426. The method of claim 2424,further comprising maintaining a temperature within the selected sectionwithin a pyrolysis temperature range.
 2427. The method of claim 2424,wherein the one or more heat sources comprise electrical heaters. 2428.The method of claim 2424, wherein the one or more heat sources comprisesurface burners.
 2429. The method of claim 2424, wherein the one or moreheat sources comprise flameless distributed combustors.
 2430. The methodof claim 2424, wherein the one or more heat sources comprise naturaldistributed combustors.
 2431. The method of claim 2424, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2432. The method of claim 2424,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2433. The method of claim 2424, wherein providing heat fromthe one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2434. The methodof claim 2424, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2435. The method of claim2424, wherein providing heat from the one or more heat sources comprisesheating the selected section such that a thermal conductivity of atleast a portion of the selected section is greater than about 0.5 W/(m °C.).
 2436. The method of claim 2424, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 2437. The method of claim 2424, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2438.The method of claim 2424, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 2439. The method of claim 2424, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 2440. The method of claim 2424, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2441. The method of claim 2424,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 2442. The method ofclaim 2424, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2443. Themethod of claim 2424, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2444. The method ofclaim 2424, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2445. The method of claim 2424, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2446. The methodof claim 2424, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2447. The method of claim2424, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2448. The method ofclaim 2424, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2449. The method of claim 2424, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2450.The method of claim 2424, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.2451. The method of claim 2424, further comprising controlling formationconditions to produce the mixture, wherein a partial pressure of H₂within the mixture is greater than about 0.5 bar.
 2452. The method ofclaim 2452, wherein the partial pressure of H₂ within the mixture ismeasured when the mixture is at a production well.
 2453. The method ofclaim 2424, further comprising altering a pressure within the formationto inhibit production of hydrocarbons from the formation having carbonnumbers greater than about
 25. 2454. The method of claim 2424, furthercomprising controlling formation conditions by recirculating a portionof hydrogen from the mixture into the formation.
 2455. The method ofclaim 2424, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 2456. The method ofclaim 2424, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2457. The method of claim 2424, wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2458. Themethod of claim 2424, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 2459. The method of claim 2424, wherein the heating iscontrolled to yield greater than about 60% by weight of condensablehydrocarbons, as measured by the Fischer Assay.
 2460. The method ofclaim 2424, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.2461. The method of claim 2424, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.2462. A method of treating a hydrocarbon containing formation in situ,comprising: providing heat from one or more heat sources to at least aportion of the formation, wherein the one or more heat sources aredisposed within one or more first wells; allowing the heat to transferfrom the one or more heat sources to a selected section of theformation; and producing a mixture from the formation through one ormore second wells, wherein one or more of the first or second wells areinitially used for a first purpose and are then used for one or moreother purposes.
 2463. The method of claim 2462, wherein the firstpurpose comprises removing water from the formation, and wherein thesecond purpose comprises providing heat to the formation.
 2464. Themethod of claim 2462, wherein the first purpose comprises removing waterfrom the formation, and wherein the second purpose comprises producingthe mixture.
 2465. The method of claim 2462, wherein the first purposecomprises heating, and wherein the second purpose comprises removingwater from the formation.
 2466. The method of claim 2462, wherein thefirst purpose comprises producing the mixture, and wherein the secondpurpose comprises removing water from the formation.
 2467. The method ofclaim 2462, wherein the one or more heat sources comprise electricalheaters.
 2468. The method of claim 2462, wherein the one or more heatsources comprise surface burners.
 2469. The method of claim 2462,wherein the one or more heat sources comprise flameless distributedcombustors.
 2470. The method of claim 2462, wherein the one or more heatsources comprise natural distributed combustors.
 2471. The method ofclaim 2462, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2472. The method ofclaim 2462, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1.0° C. per dayduring pyrolysis.
 2473. The method of claim 2462, wherein providing heatfrom the one or more heat sources to at least the portion of theformation comprises: heating a selected volume (V) of the hydrocarboncontaining formation from the one or more heat sources, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 2474. Themethod of claim 2462, wherein providing heat from the one or more heatsources comprises heating the selected section such that a thermalconductivity of at least a portion of the selected section is greaterthan about 0.5 W/(m ° C.).
 2475. The method of claim 2462, wherein theproduced mixture comprises condensable hydrocarbons having an APIgravity of at least about 25°.
 2476. The method of claim 2462, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 2477. The method of claim 2462, wherein theproduced mixture comprises non-condensable hydrocarbons, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2478. The method of claim 2462,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 2479. The method ofclaim 2462, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2480. Themethod of claim 2462, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2481. Themethod of claim 2462, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2482. Themethod of claim 2462, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2483. The method ofclaim 2462, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2484. The method of claim 2462, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 2485. The methodof claim 2462, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 2486. The method of claim2462, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 2487. The method ofclaim 2462, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.2488. The method of claim 2462, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 2489.The method of claim 2462, further comprising controlling a pressurewithin at least a majority of the selected section of the formation,wherein the controlled pressure is at least about 2.0 bar absolute.2490. The method of claim 2462, further comprising controlling formationconditions to produce a mixture of condensable hydrocarbons and H₂,wherein a partial pressure of H₂ within the mixture is greater thanabout 0.5 bar.
 2491. The method of claim 2490, wherein the partialpressure of H₂ is measured when the mixture is at a production well.2492. The method of claim 2462, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 2493. The methodof claim 2462, further comprising controlling formation conditions,wherein controlling formation conditions comprises recirculating aportion of hydrogen from the mixture into the formation.
 2494. Themethod of claim 2462, further comprising: providing hydrogen (H₂) to theheated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 2495. Themethod of claim 2462, wherein the produced mixture comprises hydrogenand condensable hydrocarbons, the method farther comprisinghydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2496. The method of claim2462, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2497. The method of claim 2462, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2498. The method ofclaim 2462, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 2499. The method of claim 2462, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heat sources are disposed in the formation foreach production well.
 2500. The method of claim 2462, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 2501. The method of claim 2462,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2502. A method for forming heaterwells in a hydrocarbon containing formation, comprising: forming a firstwellbore in the formation; forming a second wellbore in the formationusing magnetic tracking such that the second wellbore is arrangedsubstantially parallel to the first wellbore; and providing at least oneheating mechanism within the first wellbore and at least one heatingmechanism within the second wellbore such that the heating mechanismscan provide heat to at least a portion of the formation.
 2503. Themethod of claim 1, wherein superposition of heat from the at least oneheating mechanism within the first wellbore and the at least one heatingmechanism within the second wellbore pyrolyzes at least somehydrocarbons within a selected section of the formation.
 2504. Themethod of claim 2502, further comprising maintaining a temperaturewithin a selected section within a pyrolysis temperature range. 2505.The method of claim 2502, wherein the heating mechanisms compriseelectrical heaters.
 2506. The method of claim 2502, wherein the heatingmechanisms comprise surface burners.
 2507. The method of claim 2502,wherein the heating mechanisms comprise flameless distributedcombustors.
 2508. The method of claim 2502, wherein the heatingmechanisms comprise natural distributed combustors.
 2509. The method ofclaim 2502, further comprising controlling a pressure and a temperaturewithin at least a majority of a selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2510. The method ofclaim 2502, further comprising controlling the heat from the heatingmechanisms such that heat transferred from the heating mechanisms to atleast the portion of the hydrocarbons is less than about 1° C. per dayduring pyrolysis.
 2511. The method of claim 2502, further comprising:heating a selected volume (V) of the hydrocarbon containing formationfrom the heating mechanisms, wherein the formation has an average heatcapacity (C_(v)), and wherein the heating pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than Pwr,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 2512. The method of claim 2502, furthercomprising allowing the heat to transfer from the heating mechanisms toat least the portion of the formation substantially by conduction. 2513.The method of claim 2502, further comprising providing heat from theheating mechanisms to at least the portion of the formation such that athermal conductivity of at least the portion of the formation is greaterthan about 0.5 W/(m ° C.).
 2514. The method of claim 2502, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons having an API gravity of atleast about 25°.
 2515. The method of claim 2502, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2516.The method of claim 2502, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.2517. The method of claim 2502, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2518.The method of claim 2502, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is oxygen.
 2519. Themethod of claim 2502, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is sulfur.
 2520. Themethod of claim 2502, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 2521. Themethod of claim 2502, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 2522. The method ofclaim 2502, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2523. Themethod of claim 2502, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2524. The method of claim2502, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2525. The method of claim 2502, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2526. The method of claim 2502, furthercomprising producing a mixture from the formation wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2527. The method of claim2502, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2528. The method of claim 2502, furthercomprising controlling a pressure within at least a majority of aselected section of the formation, wherein the controlled pressure is atleast about 2.0 bar absolute.
 2529. The method of claim 2528, whereinthe partial pressure of H₂ within the mixture is greater than about 0.5bar.
 2530. The method of claim 2502, further comprising producing amixture from the formation, wherein the partial pressure of H₂ withinthe mixture is measured when the mixture is at a production well. 2531.The method of claim 2502, further comprising altering a pressure withinthe formation to inhibit production of hydrocarbons from the formationhaving carbon numbers greater than about
 25. 2532. The method of claim2502, further comprising producing a mixture from the formation andcontrolling formation conditions by recirculating a portion of hydrogenfrom the mixture into the formation.
 2533. The method of claim 2502,further comprising: providing hydrogen (H₂) to the portion tohydrogenate hydrocarbons within the formation; and heating a portion ofthe formation with heat from hydrogenation.
 2534. The method of claim2502, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2535. The method of claim 2502, further comprisingallowing heat to transfer from the heating mechanisms to a selectedsection of the formation to pyrolyze at least some hydrocarbons withinthe selected section such that a permeability of a majority of aselected section of the formation increases to greater than about 100millidarcy.
 2536. The method of claim 2502, further comprising allowingheat to transfer from the heating mechanisms to a selected section ofthe formation to pyrolyze at least some hydrocarbons within the selectedsection such that a permeability of a majority of the selected sectionincreases substantially uniformly.
 2537. The method of claim 2502,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2538. The method of claim 2502, further comprising producing a mixturein a production well, and wherein at least about 7 heat sources aredisposed in the formation for each production well.
 2539. The method ofclaim 2502, further comprising forming a production well in theformation using magnetic tracking such that the production well issubstantially parallel to the first wellbore and coupling a wellhead tothe third wellbore.
 2540. The method of claim 2502, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 2541. The method of claim 2502,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2542. A method for installing aheater well into a hydrocarbon containing formation, comprising: forminga bore in the ground using a steerable motor and an accelerometer; andproviding a heating mechanism within the bore such that the heatingmechanism can transfer heat to at least a portion of the formation.2543. The method of claim 2542, further comprising installing at leasttwo heater wells, and wherein superposition of heat from at least thetwo heater wells pyrolyzes at least some hydrocarbons within a selectedsection of the formation.
 2544. The method of claim 2542, furthercomprising maintaining a temperature within a selected section within apyrolysis temperature range.
 2545. The method of claim 2542, wherein theheating mechanism comprises an electrical heater.
 2546. The method ofclaim 2542, wherein the heating mechanism comprises a surface burner.2547. The method of claim 2542, wherein the heating mechanism comprisesa flameless distributed combustor.
 2548. The method of claim 2542,wherein the heating mechanism comprises a natural distributed combustor.2549. The method of claim 2542, further comprising controlling apressure and a temperature within at least a majority of a selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 2550. The method of claim 2542, further comprisingcontrolling the heat from the heating mechanism such that heattransferred from the heating mechanism to at least the portion of theformation is less than about 1° C. per day during pyrolysis.
 2551. Themethod of claim 2542, further comprising: heating a selected volume (V)of the hydrocarbon containing formation from the heating mechanism,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.2552. The method of claim 2542, further comprising allowing the heat totransfer from the heating mechanism to at least the portion of theformation substantially by conduction.
 2553. The method of claim 2542,further comprising providing heat from the heating mechanism to at leastthe portion of the formation such that a thermal conductivity of atleast the portion of the formation is greater than about 0.5 W/(m ° C.).2554. The method of claim 2542, further comprising producing a mixturefrom the formation, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 2555. Themethod of claim 2542, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2556. The method of claim2542, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2557. The method of claim 2542,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2558. The method of claim 2542,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2559. The method of claim 2542,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2560. The method of claim 2542,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds and wherein the oxygen containing compoundscomprise phenols.
 2561. The method of claim 2542, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2562.The method of claim 2542, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2563. The method of claim 2542, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2564. The method of claim2542, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2565. The method of claim 2542, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2566. The method of claim 2542, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2567. The method of claim2542, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2568. The method of claim 2542, furthercomprising controlling a pressure within at least a majority of aselected section of the formation, wherein the controlled pressure is atleast about 2.0 bar absolute.
 2569. The method of claim 2542, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bar.
 2570. The method of claim 2569, wherein thepartial pressure of H₂ within the mixture is measured when the mixtureis at a production well.
 2571. The method of claim 2542, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 2572. The method of claim 2542, furthercomprising producing a mixture from the formation and controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2573. The method of claim 2542, furthercomprising: providing hydrogen (H₂) to the at least the heated portionto hydrogenate hydrocarbons within the formation; and heating a portionof the formation with heat from hydrogenation.
 2574. The method of claim2542, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2575. The method of claim 2542, further comprisingallowing heat to transfer from the heating mechanism to a selectedsection of the formation to pyrolyze at least some hydrocarbons withinthe selected section such that a permeability of a majority of aselected section of the formation increases to greater than about 100millidarcy.
 2576. The method of claim 2542, further comprising allowingheat to transfer from the heating mechanism to a selected section of theformation to pyrolyze at least some hydrocarbons within the selectedsection such that a permeability of a majority of the selected sectionincreases substantially uniformly.
 2577. The method of claim 2542,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2578. The method of claim 2542, further comprising producing a mixturein a production well, and wherein at least about 7 heating mechanismsare disposed in the formation for each production well.
 2579. The methodof claim 2542, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.2580. The method of claim 2542, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.2581. A method for installing of wells in a hydrocarbon containingformation, comprising: forming a wellbore in the formation by geosteereddrilling; and providing a heating mechanism within the wellbore suchthat the heating mechanism can transfer heat to at least a portion ofthe formation.
 2582. The method of claim 2581, further comprisingmaintaining a temperature within a selected section within a pyrolysistemperature range.
 2583. The method of claim 2581, wherein the heatingmechanism comprises an electrical heater.
 2584. The method of claim2581, wherein the heating mechanism comprises a surface burner. 2585.The method of claim 2581, wherein the heating mechanism comprises aflameless distributed combustor.
 2586. The method of claim 2581, whereinthe heating mechanism comprises a natural distributed combustor. 2587.The method of claim 2581, further comprising controlling a pressure anda temperature within at least a majority of a selected section of theformation, wherein the pressure is controlled as a function oftemperature, or the temperature is controlled as a function of pressure.2588. The method of claim 2581, further comprising controlling the heatfrom the heating mechanism such that heat transferred from the heatingmechanism to at least the portion of the formation is less than about 1°C. per day during pyrolysis.
 2589. The method of claim 2581, furthercomprising: heating a selected volume (V) of the hydrocarbon containingformation from the heating mechanism, wherein the formation has anaverage heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2590. The methodof claim 2581, further comprising allowing the heat to transfer from theheating mechanism to at least the portion of the formation substantiallyby conduction.
 2591. The method of claim 2581, further comprisingproviding heat from the heating mechanism to at least the portion of theformation such that a thermal conductivity of at least the portion ofthe formation is greater than about 0.5 W/(m ° C.).
 2592. The method ofclaim 2581, further comprising producing a mixture from the formation,wherein the produced mixture comprises condensable hydrocarbons havingan API gravity of at least about 25°.
 2593. The method of claim 2581,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 2594. The method of claim 2581, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises non-condensable hydrocarbons, and wherein a molar ratio ofethene to ethane in the non-condensable hydrocarbons ranges from about0.001 to about 0.15.
 2595. The method of claim 2581, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 2596. The method of claim 2581, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 2597. The method of claim 2581, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about1% by weight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2598. The method of claim 2581, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises condensable hydrocarbons, wherein about 5% by weightto about 30% by weight of the condensable hydrocarbons comprise oxygencontaining compounds, and wherein the oxygen containing compoundscomprise phenols.
 2599. The method of claim 2581, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2600.The method of claim 2581, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2601. The method of claim 2581, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2602. The method of claim2581, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2603. The method of claim 2581, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2604. The method of claim 2581, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2605. The method of claim2581, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2606. The method of claim 2581, furthercomprising controlling a pressure within at least a majority of aselected section of the formation, wherein the controlled pressure is atleast about 2.0 bar absolute.
 2607. The method of claim 2581, furthercomprising controlling formation conditions to produce a mixture fromthe formation, wherein a partial pressure of H₂ within the mixture isgreater than about 0.5 bar.
 2608. The method of claim 2607, wherein thepartial pressure of H₂ within the mixture is measured when the mixtureis at a production well.
 2609. The method of claim 2581, furthercomprising altering a pressure within the formation to inhibitproduction of hydrocarbons from the formation having carbon numbersgreater than about
 25. 2610. The method of claim 2581, furthercomprising producing a mixture from the formation and controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2611. The method of claim 2581, furthercomprising: providing hydrogen (H₂) to at least the heated portion tohydrogenate hydrocarbons within the formation; and heating a portion ofthe formation with heat from hydrogenation.
 2612. The method of claim2581, further comprising: producing hydrogen and condensablehydrocarbons from the formation: and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2613. The method of claim 2581, further comprisingallowing heat to transfer from the heating mechanism to a selectedsection of the formation to pyrolyze at least some hydrocarbons withinthe selected section such that a permeability of a majority of aselected section of the formation increases to greater than about 100millidarcy.
 2614. The method of claim 2581, further comprising allowingheat to transfer from the heating mechanism to a selected section of theformation to pyrolyze at least some hydrocarbons within the selectedsection such that a permeability of a majority of the selected sectionincreases substantially uniformly.
 2615. The method of claim 2581,further comprising controlling the heat to yield greater than about 60%by weight of condensable hydrocarbons, as measured by the Fischer Assay.2616. The method of claim 2581, further comprising producing a mixturein a production well, and wherein at least about 7 heat sources aredisposed in the formation for each production well.
 2617. The method ofclaim 2581, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.2618. The method of claim 2581, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.2619. A method of treating a hydrocarbon containing formation in situ,comprising: heating a selected section of the formation with a heatingelement placed within a wellbore, wherein at least one end of theheating element is free to move axially within the wellbore to allow forthermal expansion of the heating element.
 2620. The method of claim2619, further comprising at least two heating elements within at leasttwo wellbores, and wherein superposition of heat from at least the twoheating elements pyrolyzes at least some hydrocarbons within a selectedsection of the formation.
 2621. The method of claim 2619, furthercomprising maintaining a temperature within the selected section withina pyrolysis temperature range.
 2622. The method of claim 2619, whereinthe heating element comprises a pipe-in-pipe healer.
 2623. The method ofclaim 2619, wherein the heating element comprises a flamelessdistributed combustor.
 2624. The method of claim 2619, wherein theheating element comprises a mineral insulated cable coupled to asupport, and wherein the support is free to move within the wellbore.2625. The method of claim 2619, wherein the heating element comprises amineral insulated cable suspended from a wellhead.
 2626. The method ofclaim 2619, further comprising controlling a pressure and a temperaturewithin at least a majority of a heated section of the formation, whereinthe pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2627. The method ofclaim 2619, further comprising controlling the heat such that an averageheating rate of the heated section is less than about 1° C. per dayduring pyrolysis.
 2628. The method of claim 2619, wherein heating thesection of the formation further comprises: heating a selected volume(V) of the hydrocarbon containing formation from the heating element,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.2629. The method of claim 2619, wherein heating the section of theformation comprises transferring heat substantially by conduction.22630. The method of claim 2619, further comprising heating the selectedsection of the formation such that a thermal conductivity of theselected section is greater than about 0.5 W/(m ° C.).
 2631. The methodof claim 2619, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 2632. Themethod of claim 2619, further comprising producing a mixture from theformation, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2633. The method of claim2619, further comprising producing a mixture from the formation, whereinthe produced mixture comprises non-condensable hydrocarbons, and whereina molar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 2634. The method of claim 2619,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 2635. The method of claim 2619,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 2636. The method of claim 2619,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2637. The method of claim 2619,further comprising producing a mixture from the formation, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2638. The method of claim 2619, further comprisingproducing a mixture from the formation, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 2639.The method of claim 2619, further comprising producing a mixture fromthe formation, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 2640. The method of claim 2619, further comprising producinga mixture from the formation, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.3% by weight ofthe condensable hydrocarbons are asphaltenes.
 2641. The method of claim2619, further comprising producing a mixture from the formation, whereinthe produced mixture comprises condensable hydrocarbons, and whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2642. The method of claim 2619, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2643. The method of claim 2619, furthercomprising producing a mixture from the formation, wherein the producedmixture comprises ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 2644. The method of claim2619, further comprising producing a mixture from the formation, whereinthe produced mixture comprises ammonia, and wherein the ammonia is usedto produce fertilizer.
 2645. The method of claim 2619, furthercomprising controlling a pressure within the selected section of theformation, wherein the controlled pressure is at least about 2.0 barabsolute.
 2646. The method of claim 2619, further comprising controllingformation conditions to produce a mixture from the formation, wherein apartial pressure of H₂ within the mixture is greater than about 0.5 bar.2647. The method of claim 2647, wherein the partial pressure of H₂within the mixture is measured when the mixture is at a production well.2648. The method of claim 2619, further comprising altering a pressurewithin the formation to inhibit production of hydrocarbons from theformation having carbon numbers greater than about
 25. 2649. The methodof claim 2619, further comprising producing a mixture from the formationand controlling formation conditions by recirculating a portion ofhydrogen from the mixture into the formation.
 2650. The method of claim2619, further comprising: providing hydrogen (H₂) to the heated sectionto hydrogenate hydrocarbons within the heated section; and heating aportion of the section with heat from hydrogenation.
 2651. The method ofclaim 2619, further comprising: producing hydrogen and condensablehydrocarbons from the formation; and hydrogenating a portion of theproduced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2652. The method of claim 2619, wherein heatingcomprises increasing a permeability of a majority of the heated sectionto greater than about 100 millidarcy.
 2653. The method of claim 2619,wherein heating comprises substantially uniformly increasing apermeability of a majority of the heated section.
 2654. The method ofclaim 2619, wherein the heating is controlled to yield greater thanabout 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 2655. The method of claim 2619, further comprisingproducing a mixture in a production well, and wherein at least about 7heat sources are disposed in the formation for each production well.2656. The method of claim 2619, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, and wherein the unit of heat sourcescomprises a triangular pattern.
 2657. The method of claim 2619, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, wherein the unit ofheat sources comprises a triangular pattern, and wherein a plurality ofthe units are repeated over an area of the formation to form arepetitive pattern of units.
 2658. A method of treating a hydrocarboncontaining formation in situ, comprising: providing heat from one ormore heat sources to at least a portion of the formation; allowing theheat to transfer from the one or more heat sources to a selected sectionof the formation; and producing a mixture from the formation through aproduction well, wherein the production well is located such that amajority of the mixture produced from the formation comprisesnon-condensable hydrocarbons and a non-condensable component comprisinghydrogen.
 2659. The method of claim 2658, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 2660. Themethod of claim 2658, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 2661.The method of claim 2658, wherein the production well is less thanapproximately 6 m from a heat source of the one or more heat sources.2662. The method of claim 2658, wherein the production well is less thanapproximately 3 m from a heat source of the one or more heat sources.2663. The method of claim 2658, wherein the production well is less thanapproximately 1.5 m from a heat source of the one or more heat sources.2664. The method of claim 2658, wherein an additional heat source ispositioned within a wellbore of the production well.
 2665. The method ofclaim 2658, wherein the one or more heat sources comprise electricalheaters.
 2666. The method of claim 2658, wherein the one or more heatsources comprise surface burners.
 2667. The method of claim 2658,wherein the one or more heat sources comprise flameless distributedcombustors.
 2668. The method of claim 2658, wherein the one or more heatsources comprise natural distributed combustors.
 2669. The method ofclaim 2658, further comprising controlling a pressure and a temperaturewithin at least a majority of the selected section of the formation,wherein the pressure is controlled as a function of temperature, or thetemperature is controlled as a function of pressure.
 2670. The method ofclaim 2658, further comprising controlling the heat such that an averageheating rate of the selected section is less than about 1° C. per dayduring pyrolysis.
 2671. The method of claim 2658, wherein providing heatfrom the one or more heat sources to at least the portion of formationcomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more heat sources, wherein the formation hasan average heat capacity (C_(v)), and wherein the heating pyrolyzes atleast some hydrocarbons within the selected volume of the formation; andwherein heating energy/day provided to the volume is equal to or lessthan Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2672. The methodof claim 2658, wherein allowing the heat to transfer from the one ormore heat sources to the selected section comprises transferring heatsubstantially by conduction.
 2673. The method of claim 2658, whereinproviding heat from the one or more heat sources comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 2674. Themethod of claim 2658, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 2675. Themethod of claim 2658, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 2676. The method of claim2658, wherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 2677. The method ofclaim 2658, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 2678.The method of claim 2658, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 2679. The method of claim 2658, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 2680. The method of claim 2658, wherein theproduced mixture comprises condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 2681. The method of claim 2658, wherein the producedmixture comprises condensable hydrocarbons, and wherein greater thanabout 20% by weight of the condensable hydrocarbons are aromaticcompounds.
 2682. The method of claim 2658, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 2683. The method of claim 2658, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 0.3% by weight of the condensable hydrocarbons areasphaltenes.
 2684. The method of claim 2658, wherein the producedmixture comprises condensable hydrocarbons, and wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 2685. The method of claim 2658, wherein the producedmixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2686. The method of claim 2658, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2687. The method of claim2658, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2688. The method of claim 2658,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 2689. The method of claim 2658,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 2690. The method of claim 2689, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2691. The method of claim 2658, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2692. The method of claim 2658, further comprising controllingformation conditions by recirculating a portion of the hydrogen from themixture into the formation.
 2693. The method of claim 2658, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 2694. The method of claim 2658, furthercomprising: producing condensable hydrocarbons from the formation; andhydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 2695. The method of claim2658, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 2696. The method of claim 2658, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 2697. The method ofclaim 2658, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 2698. The method of claim 2658, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heat sources are disposed in the formation foreach production well.
 2699. The method of claim 2658, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 2700. The method of claim 2658,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 2701. A method of treating ahydrocarbon containing formation in situ, comprising: providing heat toat least a portion of the formation from one or more first heat sourcesplaced within a pattern in the formation; allowing the heat to transferfrom the one or more first heat sources to a first section of theformation; heating a second section of the formation with at least onesecond heat source, wherein the second section is located within thefirst section, and wherein at least the one second heat source isconfigured to raise an average temperature of a portion of the secondsection to a higher temperature than an average temperature of the firstsection; and producing a mixture from the formation through a productionwell positioned within the second section, wherein a majority of theproduced mixture comprises non-condensable hydrocarbons and anon-condensable component comprising H₂ components.
 2702. The method ofclaim 2701, wherein the one or more first heat sources comprise at leasttwo heat sources, and wherein superposition of heat from at least thetwo heat sources pyrolyzes at least some hydrocarbons within the firstsection of the formation.
 2703. The method of claim 2701, furthercomprising maintaining a temperature within the first section within apyrolysis temperature range.
 2704. The method of claim 2701, wherein atleast the one heat source comprises a heater element positioned withinthe production well.
 2705. The method of claim 2701, wherein at leastthe one second heat source comprises an electrical heater.
 2706. Themethod of claim 2701, wherein at least the one second heat sourcecomprises a surface burner.
 2707. The method of claim 2701, wherein atleast the one second heat source comprises a flameless distributedcombustor.
 2708. The method of claim 2701, wherein at least the onesecond heat source comprises a natural distributed combustor.
 2709. Themethod of claim 2701, further comprising controlling a pressure and atemperature within at least a majority of the first or the secondsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 2710. The method of claim 2701 further comprisingcontrolling the heat such that an average heating rate of the firstsection is less than about 1° C. per day during pyrolysis.
 2711. Themethod of claim 2701 wherein providing heat to the formation furthercomprises: heating a selected volume (V) of the hydrocarbon containingformation from the one or more first heat sources, wherein the formationhas an average heat capacity (C_(v)), and wherein the heating pyrolyzesat least some hydrocarbons within the selected volume of the formation;and wherein heating energy/day provided to the volume is equal to orless than Pwr, wherein Pwr is calculated by the equation: Pwr=h*V*C_(v)*ρ_(B) wherein Pwr is the heating energy/day, h is an averageheating rate of the formation, ρ_(B) is formation bulk density, andwherein the heating rate is less than about 10° C./day.
 2712. The methodof claim 2701, wherein allowing the heat to transfer comprisestransferring heat substantially by conduction.
 2713. The method of claim2701, wherein providing heat from the one or more first heat sourcescomprises heating the first section such that a thermal conductivity ofat least a portion of the first section is greater than about 0.5 W/(m °C.).
 2714. The method of claim 2701, wherein the produced mixturecomprises condensable hydrocarbons having an API gravity of at leastabout 25°.
 2715. The method of claim 2701, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 2716.The method of claim 2701, wherein a molar ratio of ethene to ethane inthe non-condensable hydrocarbons ranges from about 0.001 to about 0.15.2717. The method of claim 2701, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2718. The method of claim 2701, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 2719. The method of claim 2701, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis of thecondensable hydrocarbons is sulfur.
 2720. The method of claim 2701,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 2721. The method of claim2701, wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 2722. The method of claim 2701,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2723. Themethod of claim 2701, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2724. The method of claim2701, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2725. The method of claim 2701, whereinthe produced mixture comprises a non-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2726. The method of claim 2701, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2727. The method of claim2701, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2728. The method of claim 2701,further comprising controlling a pressure within at least a majority ofthe first or the second section of the formation, wherein the controlledpressure is at least about 2.0 bar absolute.
 2729. The method of claim2701, further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 2730. The method of claim 2729, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2731. The method of claim 2701, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2732. The method of claim 2701, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2733. The method of claim 2701, furthercomprising: providing hydrogen (H₂) to the first or second section tohydrogenate hydrocarbons within the first or second section,respectively; and heating a portion of the first or second section,respectively, with heat from hydrogenation.
 2734. The method of claim2701, further comprising: producing condensable hydrocarbons from theformation; and hydrogenating a portion of the produced condensablehydrocarbons with at least a portion of the produced hydrogen.
 2735. Themethod of claim 2701, wherein allowing the heat to transfer comprisesincreasing a permeability of a majority of the first or second sectionto greater than about 100 millidarcy.
 2736. The method of claim 2701,wherein allowing the heat to transfer comprises substantially uniformlyincreasing a permeability of a majority of the first or second section.2737. The method of claim 2701, wherein heating the first or the secondsection is controlled to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 2738. Themethod of claim 2701, wherein at least about 7 heat sources are disposedin the formation for each production well.
 2739. The method of claim2701, further comprising providing heat from three or more heat sourcesto at least a portion of the formation, wherein three or more of theheat sources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2740.The method of claim 2701, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2741. A methodof treating a hydrocarbon containing formation in situ, comprising:providing heat into the formation from a plurality of heat sourcesplaced in a pattern within the formation, wherein a spacing between heatsources is greater than about 6 m; allowing the heat to transfer fromthe plurality of heat sources to a selected section of the formation;producing a mixture from the formation from a plurality of productionwells, wherein the plurality of production wells are positioned withinthe pattern, and wherein a spacing between production wells is greaterthan about 12 m.
 2742. The method of claim 2741, wherein superpositionof heat from the plurality of heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 2743. Themethod of claim 2741, further comprising maintaining a temperaturewithin the selected section within a pyrolysis temperature range. 2744.The method of claim 2741, wherein the plurality of heat sourcescomprises electrical heaters.
 2745. The method of claim 2741, whereinthe plurality of heat sources comprises surface burners.
 2746. Themethod of claim 2741, wherein the plurality of heat sources comprisesflameless distributed combustors.
 2747. The method of claim 2741,wherein the plurality of heat sources comprises natural distributedcombustors.
 2748. The method of claim 2741, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe selected section of the formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 2749. The method of claim 2741,further comprising controlling the heat such that an average heatingrate of the selected section is less than about 1° C. per day duringpyrolysis.
 2750. The method of claim 2741, wherein providing heat fromthe plurality of heat comprises: heating a selected volume (V) of thehydrocarbon containing formation from the plurality of heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.2751. The method of claim 2741 wherein allowing the heat to transfercomprises transferring heat substantially by conduction.
 2752. Themethod of claim 2741 wherein providing heat comprises heating theselected formation such that a thermal conductivity of at least aportion of the selected section is greater than about 0.5 W/(m ° C.).2753. The method of claim 2741, wherein the produced mixture comprisescondensable hydrocarbons having an API gravity of at least about 25°.2754. The method of claim 2741, wherein the produced mixture comprisescondensable hydrocarbons, and wherein about 0.1% by weight to about 15%by weight of the condensable hydrocarbons are olefins.
 2755. The methodof claim 2741, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.2756. The method of claim 2741, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 2757. The method of claim 2741, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 2758. The method of claim 2741, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 2759. The method of claim 2741,wherein the produced mixture comprises condensable hydrocarbons, whereinabout 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 2760. The method of claim2741 wherein the produced mixture comprises condensable hydrocarbons,and wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 2761. The method of claim 2741,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 2762. Themethod of claim 2741, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 2763. The method of claim2741, wherein the produced mixture comprises condensable hydrocarbons,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 2764. The method of claim 2741, whereinthe produced mixture comprises anon-condensable component, wherein thenon-condensable component comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable component, andwherein the hydrogen is less than about 80% by volume of thenon-condensable component.
 2765. The method of claim 2741, wherein theproduced mixture comprises ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 2766. The method of claim2741, wherein the produced mixture comprises ammonia, and wherein theammonia is used to produce fertilizer.
 2767. The method of claim 2741,further comprising controlling a pressure within at least a majority ofthe selected section of the formation, wherein the controlled pressureis at least about 2.0 bar absolute.
 2768. The method of claim 2741,further comprising controlling formation conditions to produce themixture, wherein a partial pressure of H₂ within the mixture is greaterthan about 0.5 bar.
 2769. The method of claim 2768, wherein the partialpressure of H₂ within the mixture is measured when the mixture is at aproduction well.
 2770. The method of claim 2741, further comprisingaltering a pressure within the formation to inhibit production ofhydrocarbons from the formation having carbon numbers greater than about25.
 2771. The method of claim 2741, further comprising controllingformation conditions by recirculating a portion of hydrogen from themixture into the formation.
 2772. The method of claim 2741, furthercomprising: providing hydrogen (H₂) to the selected section tohydrogenate hydrocarbons within the selected section; and heating aportion of the selected section with heat from hydrogenation.
 2773. Themethod of claim 2741, further comprising: producing hydrogen andcondensable hydrocarbons from the formation; and hydrogenating a portionof the produced condensable hydrocarbons with at least a portion of theproduced hydrogen.
 2774. The method of claim 2741 wherein allowing theheat to transfer comprises increasing a permeability of a majority ofthe selected section to greater than about 100 millidarcy.
 2775. Themethod of claim 2741, wherein allowing the heat to transfer comprisessubstantially uniformly increasing a permeability of a majority of theselected section.
 2776. The method of claim 2741, further comprisingcontrolling the heat to yield greater than about 60% by weight ofcondensable hydrocarbons, as measured by the Fischer Assay.
 2777. Themethod of claim 2741, wherein at least about 7 heat sources are disposedin the formation for each production well.
 2778. The method of claim2741, further comprising providing heat from three or more heal sourcesto at least a portion of the formation, wherein three or more of theheat sources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 2779.The method of claim 2741, further comprising providing heat from threeor more heal sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 2780. A systemconfigured to heat a hydrocarbon containing formation, comprising: aheater disposed in an opening in the formation, wherein the heater isconfigured to provide heat to at least a portion of the formation duringuse; an oxidizing fluid source; a conduit disposed in the opening,wherein the conduit is configured to provide an oxidizing fluid from theoxidizing fluid source to a reaction zone in the formation during use,and wherein the oxidizing fluid is selected to oxidize at least somehydrocarbons at the reaction zone during use such that heat is generatedat the reaction zone; and wherein the system is configured to allow heatto transfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 2781. The system of claim2780, wherein the oxidizing fluid is configured to generate heat in thereaction zone such that the oxidizing fluid is transported through thereaction zone substantially by diffusion.
 2782. The system of claim2780, wherein the conduit comprises orifices, and wherein the orificesare configured to provide the oxidizing fluid into the opening. 2783.The system of claim 2780, wherein the conduit comprises critical floworifices, and wherein the critical flow orifices are configured tocontrol a flow of the oxidizing fluid such that a rate of oxidation inthe formation is controlled.
 2784. The system of claim 2780, wherein theconduit is further configured to be cooled with the oxidizing fluid suchthat the conduit is not substantially heated by oxidation.
 2785. Thesystem of claim 2780, wherein the conduit is further configured toremove an oxidation product.
 2786. The system of claim 2780, wherein theconduit is further configured to remove an oxidation product such thatthe oxidation product transfers substantial heat to the oxidizing fluid.2787. The system of claim 2780, wherein the conduit is furtherconfigured to remove an oxidation product, and wherein a flow rate ofthe oxidizing fluid in the conduit is approximately equal to a flow rateof the oxidation product in the conduit.
 2788. The system of claim 2780,wherein the conduit is further configured to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.2789. The system of claim 2780, wherein the conduit is furtherconfigured to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 2790. The system of claim 2780,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 2791. The system ofclaim 2780, further comprising a center conduit disposed within theconduit, wherein the center conduit is configured to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configured to remove an oxidation product during use.
 2792. Thesystem of claim 2780, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2793. The system of claim 2780, further comprising a conductor disposedin a second conduit, wherein the second conduit is disposed within theopening, and wherein the conductor is configured to heat at least aportion of the formation during application of an electrical current tothe conductor.
 2794. The system of claim 2780, further comprising aninsulated conductor disposed within the opening, wherein the insulatedconductor is configured to heat at least a portion of the formationduring application of an electrical current to the insulated conductor.2795. The system of claim 2780, further comprising at least oneelongated member disposed within the opening, wherein the at least theone elongated member is configured to heat at least a portion of theformation during application of an electrical current to the at leastthe one elongated member.
 2796. The system of claim 2780, furthercomprising a heat exchanger disposed external to the formation, whereinthe heat exchanger is configured to heat the oxidizing fluid, whereinthe conduit is further configured to provide the heated oxidizing fluidinto the opening during use, and wherein the heated oxidizing fluid isconfigured to heat at least a portion of the formation during use. 2797.The system of claim 2780, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 2798. The system of claim 2780, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 2799. The system of claim2780, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 2800. The system of claim 2780, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 2801. The system ofclaim 2780, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 2802. The system of claim2780, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 2803. The system of claim 2780, wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 2804. A system configurable to heata hydrocarbon containing formation, comprising: a heater configurable tobe disposed in an opening in the formation, wherein the heater isfurther configurable to provide heat to at least a portion of theformation during use, a conduit configurable to be disposed in theopening, wherein the conduit is configurable to provide an oxidizingfluid from an oxidizing fluid source to a reaction zone in the formationduring use, and wherein the system is configurable to allow theoxidizing fluid to oxidize at least some hydrocarbons at the reactionzone during use such that heat is generated at the reaction zone; andwherein the system is further configurable to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 2805. The system of claim 2804, wherein theoxidizing fluid is configurable to generate heat in the reaction zonesuch that the oxidizing fluid is transported through the reaction zonesubstantially by diffusion.
 2806. The system of claim 2804, wherein theconduit comprises orifices, and wherein the orifices are configurable toprovide the oxidizing fluid into the opening.
 2807. The system of claim2804, wherein the conduit comprises critical flow orifices, and whereinthe critical flow orifices are configurable to control a flow of theoxidizing fluid such that a rate of oxidation in the formation iscontrolled.
 2808. The system of claim 2804, wherein the conduit isfurther configurable to be cooled with the oxidizing fluid such that theconduit is not substantially heated by oxidation.
 2809. The system ofclaim 2804, wherein the conduit is further configurable to remove anoxidation product.
 2810. The system of claim 2804, wherein the conduitis further configurable to remove an oxidation product such that theoxidation product transfers heat to the oxidizing fluid.
 2811. Thesystem of claim 2804, wherein the conduit is further configurable toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 2812. The system of claim 2804,wherein the conduit is further configurable to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.2813. The system of claim 2804, wherein the conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 2814. The system of claim 2804,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 2815. The system ofclaim 2804, further comprising a center conduit disposed within theconduit, wherein center conduit is configurable to provide the oxidizingfluid into the opening during use, and wherein the conduit is furtherconfigurable to remove an oxidation product during use.
 2816. The systemof claim 2804, wherein the portion of the formation extends radiallyfrom the opening a width of less than approximately 0.2 m.
 2817. Thesystem of claim 2804, further comprising a conductor disposed in asecond conduit, wherein the second conduit is disposed within theopening, and wherein the conductor is configurable to heat at least aportion of the formation during application of an electrical current tothe conductor.
 2818. The system of claim 2804, further comprising aninsulated conductor disposed within the opening, wherein the insulatedconductor is configurable to heat at least a portion of the formationduring application of an electrical current to the insulated conductor.2819. The system of claim 2804, further comprising at least oneelongated member disposed within the opening wherein the at least theone elongated member is configurable to heat at least a portion of theformation during application of an electrical current to the at leastthe one elongated member.
 2820. The system of claim 2804, furthercomprising a heat exchanger disposed external to the formation, whereinthe heat exchanger is configurable to heat the oxidizing fluid, whereinthe conduit is further configurable to provide the heated oxidizingfluid into the opening during use, and wherein the heated oxidizingfluid is configurable to heat at least a portion of the formation duringuse.
 2821. The system of claim 2804, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation.
 2822. The system of claim 2804,further comprising an overburden casing coupled to the opening whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 2823. The system of claim2804, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 2824. The system of claim 2804, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 2825. The system ofclaim 2804, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 2826. The system of claim2804, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 2827. The system of claim 2804, wherein the system isfurther configurable such that transferred heat can pyrolyze at leastsome hydrocarbons in the pyrolysis zone.
 2828. An in situ method forheating a hydrocarbon containing formation, comprising: heating aportion of the formation to a temperature sufficient to support reactionof hydrocarbons within the portion of the formation with an oxidizingfluid; providing the oxidizing fluid to a reaction zone in theformation; allowing the oxidizing fluid to react with at least a portionof the hydrocarbons at the reaction zone to generate heat at thereaction zone; and transferring the generated heat substantially byconduction from the reaction zone to a pyrolysis zone in the formation.2829. The method of claim 2828, further comprising transporting theoxidizing fluid through the reaction zone by diffusion.
 2830. The methodof claim 2828 further comprising directing at least a portion of theoxidizing fluid into the opening through orifices of a conduit disposedin the opening.
 2831. The method of claim 2828, further comprisingcontrolling a flow of the oxidizing fluid with critical flow orifices ofa conduit disposed in the opening such that a rate of oxidation iscontrolled.
 2832. The method of claim 2828, further comprisingincreasing a flow of the oxidizing fluid in the opening to accommodatean increase in a volume of the reaction zone such that a rate ofoxidation is substantially constant over time within the reaction zone.2833. The method of claim 2828, wherein a conduit is disposed in theopening the method further comprising cooling the conduit with theoxidizing fluid to reduce heating of the conduit by oxidation.
 2834. Themethod of claim 2828, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit.
 2835. The method of claim 2828, wherein aconduit is disposed within the opening, the method further comprisingremoving an oxidation product from the formation through the conduit andtransferring heat from the oxidation product in the conduit to oxidizingfluid in the conduit.
 2836. The method of claim 2828, wherein a conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the conduit, wherein aflow rate of the oxidizing fluid in the conduit is approximately equalto a flow rate of the oxidation product in the conduit.
 2837. The methodof claim 2828, wherein a conduit is disposed within the opening, themethod further comprising removing an oxidation product from theformation through the conduit and controlling a pressure between theoxidizing fluid and the oxidation product in the conduit to reducecontamination of the oxidation product by the oxidizing fluid.
 2838. Themethod of claim 2828, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit and substantially inhibiting the oxidationproduct from flowing into portions of the formation beyond the reactionzone.
 2839. The method of claim 2828, further comprising substantiallyinhibiting the oxidizing fluid from flowing into portions of theformation beyond the reaction zone.
 2840. The method of claim 2828,wherein a center conduit is disposed within an outer conduit, andwherein the outer conduit is disposed within the opening, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theouter conduit.
 2841. The method of claim 2828, wherein the portion ofthe formation extends radially from the opening a width of less thanapproximately 0.2 m.
 2842. The method of claim 2828, wherein heating theportion comprises applying electrical current to a conductor disposed ina conduit, wherein the conduit is disposed within the opening.
 2843. Themethod of claim 2828, wherein heating the portion comprises applyingelectrical current to an insulated conductor disposed within theopening.
 2844. The method of claim 2828, wherein heating the portioncomprises applying electrical current to at least one elongated memberdisposed within the opening.
 2845. The method of claim 2828, whereinheating the portion comprises heating the oxidizing fluid in a heatexchanger disposed external to the formation such that providing theoxidizing fluid into the opening comprises transferring heat from theheated oxidizing fluid to the portion.
 2846. The method of claim 2828further comprising removing water from the formation prior to heatingthe portion.
 2847. The method of claim 2828, further comprisingcontrolling the temperature of the formation to substantially inhibitproduction of oxides of nitrogen during oxidation.
 2848. The method ofclaim 2828, further comprising coupling an overburden casing to theopening wherein the overburden casing is disposed in an overburden ofthe formation.
 2849. The method of claim 2828, further comprisingcoupling an overburden casing to the opening, wherein the overburdencasing is disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 2850. The method of claim 2828,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 2851. Themethod of claim 2828, further comprising coupling an overburden casingto the opening, wherein a packing material is disposed at a junction ofthe overburden casing and the opening.
 2852. The method of claim 2828,wherein the pyrolysis zone is substantially adjacent to the reactionzone.
 2853. A system configured to heat a hydrocarbon containingformation, comprising: a heater disposed in an opening in the formation,wherein the heater is configured to provide heat to at least a portionof the formation during use; an oxidizing fluid source; a conduitdisposed in the opening, wherein the conduit is configured to provide anoxidizing fluid from the oxidizing fluid source to a reaction zone inthe formation during use, wherein the oxidizing fluid is selected tooxidize at least some hydrocarbons at the reaction zone during use suchthat heat is generated at the reaction zone, and wherein the conduit isfurther configured to remove an oxidation product from the formationduring use; and wherein the system is configured to allow heat totransfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 2854. The system of claim2853, wherein the oxidizing fluid is configured to generate heat in thereaction zone such that the oxidizing fluid is transported through thereaction zone substantially by diffusion.
 2855. The system of claim2853, wherein the conduit comprises orifices and wherein the orificesare configured to provide the oxidizing fluid into the opening. 2856.The system of claim 2853, wherein the conduit comprises critical floworifices, and wherein the critical flow orifices are configured tocontrol a flow of the oxidizing fluid such that a rate of oxidation inthe formation is controlled.
 2857. The system of claim 2853, wherein theconduit is further configured to be cooled with the oxidizing fluid suchthat the conduit is not substantially heated by oxidation.
 2858. Thesystem of claim 2853, wherein the conduit is further configured suchthat the oxidation product transfers heat to the oxidizing fluid. 2859.The system of claim 2853, wherein a flow rate of the oxidizing fluid inthe conduit is approximately equal to a flow rate of the oxidationproduct in the conduit.
 2860. The system of claim 2853, wherein apressure of the oxidizing fluid in the conduit and a pressure of theoxidation product in the conduit are controlled to reduce contaminationof the oxidation product by the oxidizing fluid.
 2861. The system ofclaim 2853, wherein the oxidation product is substantially inhibitedfrom flowing into portions of the formation beyond the reaction zone.2862. The system of claim 2853, wherein the oxidizing fluid issubstantially inhibited from flowing into portions of the formationbeyond the reaction zone.
 2863. The system of claim 2853, furthercomprising a center conduit disposed within the conduit, wherein thecenter conduit is configured to provide the oxidizing fluid into theopening during use.
 2864. The system of claim 2853, wherein the portionof the formation extends radially from the opening a width of less thanapproximately 0.2 m.
 2865. The system of claim 2853, further comprisinga conductor disposed in a second conduit, wherein the second conduit isdisposed within the opening, and wherein the conductor is configured toheat at least a portion of the formation during application of anelectrical current to the conductor.
 2866. The system of claim 2853,further comprising an insulated conductor disposed within the opening,wherein the insulated conductor is configured to heat at least a portionof the formation during application of an electrical current to theinsulated conductor.
 2867. The system of claim 2853, further comprisingat least one elongated member disposed within the opening, wherein theat least the one elongated member is configured to heat at least aportion of the formation during application of an electrical current tothe at least the one elongated member.
 2868. The system of claim 2853,further comprising a heat exchanger disposed external to the formation,wherein the heat exchanger is configured to heat the oxidizing fluid,wherein the conduit is further configured to provide the heatedoxidizing fluid into the opening during use, and wherein the heatedoxidizing fluid is configured to heat at least a portion of theformation during use.
 2869. The system of claim 2853, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 2870. The systemof claim 2853, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 2871.The system of claim 2853 further comprising an overburden casing coupledto the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 2872. The system of claim 2853, furthercomprising an overburden casing coupled to the opening wherein a packingmaterial is disposed at a junction of the overburden casing and theopening.
 2873. The system of claim 2853, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configured to substantiallyinhibit a flow of fluid between the opening and the overburden casingduring use.
 2874. The system of claim 2853, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material comprises cement.
 2875. Thesystem of claim 2853, wherein the system is further configured such thattransferred heat can pyrolyze at least some hydrocarbons in thepyrolysis zone.
 2876. A system configurable to heat a hydrocarboncontaining formation comprising: a heater configurable to be disposed inan opening in the formation, wherein the heater is further configurableto provide heat to at least a portion of the formation during use; aconduit configurable to be disposed in the opening, wherein the conduitis further configurable to provide an oxidizing fluid from an oxidizingfluid source to a reaction zone in the formation during use, wherein thesystem is configurable to allow the oxidizing fluid to oxidize at leastsome hydrocarbons at the reaction zone during use such that heat isgenerated at the reaction zone, and wherein the conduit is furtherconfigurable to remove an oxidation product from the formation duringuse; and wherein the system is further configurable to allow heat totransfer substantially by conduction from the reaction zone to apyrolysis zone during use.
 2877. The system of claim 2876, wherein theoxidizing fluid is configurable to generate heat in the reaction zonesuch that the oxidizing fluid is transported through the reaction zonesubstantially by diffusion.
 2878. The system of claim 2876, wherein theconduit comprises orifices, and wherein the orifices are configurable toprovide the oxidizing fluid into the opening.
 2879. The system of claim2876, wherein the conduit comprises critical flow orifices, and whereinthe critical flow orifices are configurable to control a flow of theoxidizing fluid such that a rate of oxidation in the formation iscontrolled.
 2880. The system of claim 2876, wherein the conduit isfurther configurable to be cooled with the oxidizing fluid such that theconduit is not substantially heated by oxidation.
 2881. The system ofclaim 2876, wherein the conduit is further configurable such that theoxidation product transfers heat to the oxidizing fluid.
 2882. Thesystem of claim 2876, wherein a flow rate of the oxidizing fluid in theconduit is approximately equal to a flow rate of the oxidation productin the conduit.
 2883. The system of claim 2876, wherein a pressure ofthe oxidizing fluid in the conduit and a pressure of the oxidationproduct in the conduit are controlled to reduce contamination of theoxidation product by the oxidizing fluid.
 2884. The system of claim2876, wherein the oxidation product is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 2885.The system of claim 2876, wherein the oxidizing fluid is substantiallyinhibited from flowing into portions of the formation beyond thereaction zone.
 2886. The system of claim 2876, further comprising acenter conduit disposed within the conduit, wherein center conduit isconfigurable to provide the oxidizing fluid into the opening during use.2887. The system of claim 2876, wherein the portion of the formationextends radially from the opening a width of less than approximately 0.2m.
 2888. The system of claim 2876, further comprising a conductordisposed in a second conduit, wherein the second conduit is disposedwithin the opening, and wherein the conductor is configurable to heat atleast a portion of the formation during application of an electricalcurrent to the conductor.
 2889. The system of claim 2876, furthercomprising an insulated conductor disposed within the opening, whereinthe insulated conductor is configurable to heat at least a portion ofthe formation during application of an electrical current to theinsulated conductor.
 2890. The system of claim 2876, further comprisingat least one elongated member disposed within the opening, wherein theat least the one elongated member is configurable to heat at least aportion of the formation during application of an electrical current tothe at least the one elongated member.
 2891. The system of claim 2876,further comprising a heat exchanger disposed external to the formation,wherein the heat exchanger is configurable to heat the oxidizing fluid,wherein the conduit is further configurable to provide the heatedoxidizing fluid into the opening during use, and wherein the heatedoxidizing fluid is configurable to heat at least a portion of theformation during use.
 2892. The system of claim 2876, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 2893. The systemof claim 2876, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 2894.The system of claim 2876, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 2895. The system of claim 2876, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 2896. The system of claim 2876, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 2897. The system of claim 2876, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.2898. The system of claim 2876, wherein the system is furtherconfigurable such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 2899. An in situ method for heatinga hydrocarbon containing formation, comprising: heating a portion of theformation to a temperature sufficient to support reaction ofhydrocarbons within the portion of the formation with an oxidizing fluidwherein the portion is located substantially adjacent to an opening inthe formation; providing the oxidizing fluid to a reaction zone in theformation; allowing the oxidizing gas to react with at least a portionof the hydrocarbons at the reaction zone to generate heat in thereaction zone; removing at least a portion of an oxidation productthrough the opening; and transferring the generated heat substantiallyby conduction from the reaction zone to a pyrolysis zone in theformation.
 2900. The method of claim 2899, further comprisingtransporting the oxidizing fluid through the reaction zone by diffusion.2901. The method of claim 2899, further comprising directing at least aportion of the oxidizing fluid into the opening through orifices of aconduit disposed in the opening.
 2902. The method of claim 2899, furthercomprising controlling a flow of the oxidizing fluid with critical floworifices of a conduit disposed in the opening such that a rate ofoxidation is controlled.
 2903. The method of claim 2899, furthercomprising increasing a flow of the oxidizing fluid in the opening toaccommodate an increase in a volume of the reaction zone such that arate of oxidation is substantially maintained within the reaction zone.2904. The method of claim 2899, wherein a conduit is disposed in theopening, the method further comprising cooling the conduit with theoxidizing fluid such that the conduit is not substantially heated byoxidation.
 2905. The method of claim 2899, wherein a conduit is disposedwithin the opening, and wherein removing at least the portion of theoxidation product through the opening comprises removing at least theportion of the oxidation product through the conduit.
 2906. The methodof claim 2899, wherein a conduit is disposed within the opening, andwherein removing at least the portion of the oxidation product throughthe opening comprises removing at least the portion of the oxidationproduct through the conduit, the method further comprising transferringsubstantial heat from the oxidation product in the conduit to theoxidizing fluid in the conduit.
 2907. The method of claim 2899, whereina conduit is disposed within the opening, wherein removing at least theportion of the oxidation product through the opening comprises removingat least the portion of the oxidation product through the conduit, andwherein a flow rate of the oxidizing fluid in the conduit isapproximately equal to a flow rate of the oxidation product in theconduit.
 2908. The method of claim 2899, wherein a conduit is disposedwithin the opening, and wherein removing at least the portion of theoxidation product through the opening comprises removing at least theportion of the oxidation product through the conduit, the method furthercomprising controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 2909. The method of claim2899, wherein a conduit is disposed within the opening, and whereinremoving at least the portion of the oxidation product through theopening comprises removing at least the portion of the oxidation productthrough the conduit, the method further comprising substantiallyinhibiting the oxidation product from flowing into portions of theformation beyond the reaction zone.
 2910. The method of claim 2899,further comprising substantially inhibiting the oxidizing fluid fromflowing into portions of the formation beyond the reaction zone. 2911.The method of claim 2899, wherein a center conduit is disposed within anouter conduit, and wherein the outer conduit is disposed within theopening, the method further comprising providing the oxidizing fluidinto the opening through the center conduit and removing at least aportion of the oxidation product through the outer conduit.
 2912. Themethod of claim 2899, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2913. The method of claim 2899 wherein heating the portion comprisesapplying electrical current to a conductor disposed in a conduit,wherein the conduit is disposed within the opening.
 2914. The method ofclaim 2899, wherein heating the portion comprises applying electricalcurrent to an insulated conductor disposed within the opening.
 2915. Themethod of claim 2899, wherein heating the portion comprises applyingelectrical current to at least one elongated member disposed within theopening.
 2916. The method of claim 2899, wherein heating the portioncomprises heating the oxidizing fluid in a heat exchanger disposedexternal to the formation such that providing the oxidizing fluid intothe opening comprises transferring heat from the heated oxidizing fluidto the portion.
 2917. The method of claim 2899, further comprisingremoving water from the formation prior to heating the portion. 2918.The method of claim 2899, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 2919. The method of claim 2899, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 2920.The method of claim 2899, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 2921. The method of claim 2899, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 2922. The method of claim 2899,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 2923. The method of claim 2899, wherein the pyrolysiszone is substantially adjacent to the reaction.
 2924. A systemconfigured to heat a hydrocarbon containing formation, comprising: anelectric heater disposed in an opening in the formation, wherein theelectric heater is configured to provide heat to at least a portion ofthe formation during use; an oxidizing fluid source: a conduit disposedin the opening, wherein the conduit is configured to provide anoxidizing fluid from the oxidizing fluid source to a reaction zone inthe formation during use, and wherein the oxidizing fluid is selected tooxidize at least some hydrocarbons at the reaction zone during use suchthat heat is generated at the reaction zone; and wherein the system isconfigured to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 2925.The system of claim 2924, wherein the oxidizing fluid is configured togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 2926.The system of claim 2924, wherein the conduit comprises orifices, andwherein the orifices are configured to provide the oxidizing fluid intothe opening.
 2927. The system of claim 2924, wherein the conduitcomprises critical flow orifices, and wherein the critical flow orificesare configured to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 2928. The system of claim2924, wherein the conduit is further configured to be cooled with theoxidizing fluid such that the conduit is not substantially heated byoxidation.
 2929. The system of claim 2924, wherein the conduit isfurther configured to remove an oxidation product.
 2930. The system ofclaim 2924, wherein the conduit is further configured to remove anoxidation product, such that the oxidation product transfers heat to theoxidizing fluid.
 2931. The system of claim 2924, wherein the conduit isfurther configured to remove an oxidation product, and wherein a flowrate of the oxidizing fluid in the conduit is approximately equal to aflow rate of the oxidation product in the conduit.
 2932. The system ofclaim 2924, wherein the conduit is further configured to remove anoxidation product, and wherein a pressure of the oxidizing fluid in theconduit and a pressure of the oxidation product in the conduit arecontrolled to reduce contamination of the oxidation product by theoxidizing fluid.
 2933. The system of claim 2924, wherein the conduit isfurther configured to remove an oxidation product, and wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone.
 2934. The system of claim2924, wherein the oxidizing fluid is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 2935.The system of claim 2924, further comprising a center conduit disposedwithin the conduit, wherein the center conduit is configured to providethe oxidizing fluid into the opening during use, and wherein the conduitis further configured to remove an oxidation product during use. 2936.The system of claim 2924, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2937. The system of claim 2924, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 2938. The system of claim 2924, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 2939. The system of claim2924, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 2940. The system of claim 2924, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 2941. The system ofclaim 2924, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 2942. The system of claim2924, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 2943. The system of claim 2924, wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 2944. A system configurable to heata hydrocarbon containing formation, comprising: an electric heaterconfigurable to be disposed in an opening in the formation wherein theelectric heater is further configurable to provide heat to at least aportion of the formation during use, and wherein at least the portion islocated substantially adjacent to the opening; a conduit configurable tobe disposed in the opening, wherein the conduit is further configurableto provide an oxidizing fluid from an oxidizing fluid source to areaction zone in the formation during use, and wherein the system isconfigurable to allow the oxidizing fluid to oxidize at least somehydrocarbons at the reaction zone during use such that heat is generatedat the reaction zone; and wherein the system is further configurable toallow heat to transfer substantially by conduction from the reactionzone to a pyrolysis zone of the formation during use.
 2945. The systemof claim 2944, wherein the oxidizing fluid is configurable to generateheat in the reaction zone such that the oxidizing fluid is transportedthrough the reaction zone substantially by diffusion.
 2946. The systemof claim 2944, wherein the conduit comprises orifices, and wherein theorifices are configurable to provide the oxidizing fluid into theopening.
 2947. The system of claim 2944, wherein the conduit comprisescritical flow orifices, and wherein the critical flow orifices areconfigurable to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 2948. The system of claim2944, wherein the conduit is further configurable to be cooled with theoxidizing fluid such that the conduit is not substantially heated byoxidation.
 2949. The system of claim 2944, wherein the conduit isfurther configurable to remove an oxidation product.
 2950. The system ofclaim 2944, wherein the conduit is further configurable to remove anoxidation product such that the oxidation product transfers heat to theoxidizing fluid.
 2951. The system of claim 2944, wherein the conduit isfurther configurable to remove an oxidation product, and wherein a flowrate of the oxidizing fluid in the conduit is approximately equal to aflow rate of the oxidation product in the conduit.
 2952. The system ofclaim 2944, wherein the conduit is further configurable to remove anoxidation product, and wherein a pressure of the oxidizing fluid in theconduit and a pressure of the oxidation product in the conduit arecontrolled to reduce contamination of the oxidation product by theoxidizing fluid.
 2953. The system of claim 2944, wherein the conduit isfurther configurable to remove an oxidation product, and wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone.
 2954. The system of claim2944, wherein the oxidizing fluid is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 2955.The system of claim 2944, further comprising a center conduit disposedwithin the conduit, wherein center conduit is configurable to providethe oxidizing fluid into the opening during use, and wherein the conduitis further configurable to remove an oxidation product during use. 2956.The system of claim 2944, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.2957. The system of claim 2944, further comprising an overburden casingcoupled to the opening wherein the overburden casing is disposed in anoverburden of the formation.
 2958. The system of claim 2944, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 2959. The system of claim2944, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 2960. The system of claim 2944, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 2961. The system ofclaim 2944, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 2962. The system of claim2944, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 2963. The system of claim 2944, wherein the system isfurther configurable such that transferred heat can pyrolyze at leastsome hydrocarbons in the pyrolysis zone.
 2964. A system configured toheat a hydrocarbon containing formation, comprising: a conductordisposed in a first conduit, wherein the first conduit is disposed in anopening in the formation, and wherein the conductor is configured toprovide heat to at least a portion of the formation during use; anoxidizing fluid source; a second conduit disposed in the opening,wherein the second conduit is configured to provide an oxidizing fluidfrom the oxidizing fluid source to a reaction zone in the formationduring use, and wherein the oxidizing fluid is selected to oxidize atleast some hydrocarbons at the reaction zone during use such that heatis generated at the reaction zone; and wherein the system is configuredto allow heat to transfer substantially by conduction from the reactionzone to a pyrolysis zone of the formation during use.
 2965. The systemof claim 2964, wherein the oxidizing fluid is configured to generateheat in the reaction zone such that the oxidizing fluid is transportedthrough the reaction zone substantially by diffusion.
 2966. The systemof claim 2964, wherein the second conduit comprises orifices, andwherein the orifices are configured to provide the oxidizing fluid intothe opening.
 2967. The system of claim 2964, wherein the second conduitcomprises critical flow orifices, and wherein the critical flow orificesare configured to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 2968. The system of claim2964, wherein the second conduit is further configured to be cooled withthe oxidizing fluid to reduce heating of the second conduit byoxidation.
 2969. The system of claim 2964, wherein the second conduit isfurther configured to remove an oxidation product.
 2970. The system ofclaim 2964, wherein the second conduit is further configured to removean oxidation product such that the oxidation product transfers heat tothe oxidizing fluid.
 2971. The system of claim 2964, wherein the secondconduit is further configured to remove an oxidation product, andwherein a flow rate of the oxidizing fluid in the conduit isapproximately equal to a flow rate of the oxidation product in thesecond conduit.
 2972. The system of claim 2964, wherein the secondconduit is further configured to remove an oxidation product, andwherein a pressure of the oxidizing fluid in the second conduit and apressure of the oxidation product in the second conduit are controlledto reduce contamination of the oxidation product by the oxidizing fluid.2973. The system of claim 2964, wherein the second conduit is furtherconfigured to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 2974. The system of claim 2964,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 2975. The system ofclaim 2964, further comprising a center conduit disposed within thesecond conduit, wherein the center conduit is configured to provide theoxidizing fluid into the opening during use, and wherein the secondconduit is further configured to remove an oxidation product during use.2976. The system of claim 2964, wherein the portion of the formationextends radially from the opening a width of less than approximately 0.2m.
 2977. The system of claim 2964, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation.
 2978. The system of claim 2964,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 2979. The system of claim2964, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 2980. The system of claim 2964, further comprising an overburdencasing coupled to the opening, wherein a packing, material is disposedat a junction of the overburden casing and the opening.
 2981. The systemof claim 2964, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 2982. The system of claim2964, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 2983. The system of claim 2964, wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 2984. A system configurable to heata hydrocarbon containing formation, comprising: a conductor configurableto be disposed in a first conduit, wherein the first conduit isconfigurable to be disposed in an opening in the formation, and whereinthe conductor is further configurable to provide heat to at least aportion of the formation during, use; a second conduit configurable tobe disposed in the opening, wherein the second conduit is furtherconfigurable to provide an oxidizing fluid from an oxidizing fluidsource to a reaction zone in the formation during use, and wherein thesystem is configurable to allow the oxidizing fluid to oxidize at leastsome hydrocarbons at the reaction zone during use such that heat isgenerated at the reaction zone; and wherein the system is furtherconfigurable to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 2985.The system of claim 2984, wherein the oxidizing fluid is configurable togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 2986.The system of claim 2984, wherein the second conduit comprises orifices,and wherein the orifices are configurable to provide the oxidizing fluidinto the opening.
 2987. The system of claim 2984, wherein the secondconduit comprises critical flow orifices, and wherein the critical floworifices are configurable to control a flow of the oxidizing fluid suchthat a rate of oxidation in the formation is controlled.
 2988. Thesystem of claim 2984, wherein the second conduit is further configurableto be cooled with the oxidizing fluid to reduce heating of the secondconduit by oxidation.
 2989. The system of claim 2984, wherein the secondconduit is further configurable to remove an oxidation product. 2990.The system of claim 2984, wherein the second conduit is furtherconfigurable to remove an oxidation product such that the oxidationproduct transfers heat to the oxidizing fluid.
 2991. The system of claim2984, wherein the second conduit is further configurable to remove anoxidation product, and wherein a flow rate of the oxidizing fluid in theconduit is approximately equal to a flow rate of the oxidation productin the second conduit.
 2992. The system of claim 2984, wherein thesecond conduit is further configurable to remove an oxidation product,and wherein a pressure of the oxidizing fluid in the second conduit anda pressure of the oxidation product in the second conduit are controlledto reduce contamination of the oxidation product by the oxidizing fluid.2993. The system of claim 2984, wherein the second conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 2994. The system of claim 2984,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 2995. The system ofclaim 2984, further comprising a center conduit disposed within thesecond conduit, wherein center conduit is configurable to provide theoxidizing fluid into the opening during use, and wherein the secondconduit is further configurable to remove an oxidation product duringuse.
 2996. The system of claim 2984, wherein the portion of theformation extends radially from the opening a width of less thanapproximately 0.2 m.
 2997. The system of claim 2984, further comprisingan overburden casing coupled to the opening wherein the overburdencasing is disposed in an overburden of the formation.
 2998. The systemof claim 2984, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 2999.The system of claim 2984, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3000. The system of claim 2984, furthercomprising an overburden casing coupled to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening.
 3001. The system of claim 2984, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3002. The system of claim 2984, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3003. The system of claim 2984, wherein the system is furtherconfigurable such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3004. An in situ method for heatinga hydrocarbon containing formation, comprising: heating a portion of theformation to a temperature sufficient to support reaction ofhydrocarbons within the portion of the formation with an oxidizingfluid, wherein heating comprises applying an electrical current to aconductor disposed in a first conduit to provide heat to the portion,and wherein the first conduit is disposed within the opening; providingthe oxidizing fluid to a reaction zone in the formation; allowing theoxidizing fluid to react with at least a portion of the hydrocarbons atthe reaction zone to generate heat at the reaction zone; andtransferring the generated heat substantially by conduction from thereaction zone to a pyrolysis zone in the formation.
 3005. The method ofclaim 3004, further comprising transporting the oxidizing fluid throughthe reaction zone by diffusion.
 3006. The method of claim 3004, furthercomprising directing at least a portion of the oxidizing fluid into theopening through orifices of a second conduit disposed in the opening.3007. The method of claim 3004, further comprising controlling a flow ofthe oxidizing fluid with critical flow orifices of a second conduitdisposed in the opening such that a rate of oxidation is controlled.3008. The method of claim 3004, further comprising increasing a flow ofthe oxidizing fluid in the opening to accommodate an increase in avolume of the reaction zone such that a rate of oxidation issubstantially constant over time within the reaction zone.
 3009. Themethod of claim 3004, wherein a second conduit is disposed in theopening, the method further comprising cooling the second conduit withthe oxidizing fluid to reduce heating of the second conduit byoxidation.
 3010. The method of claim 3004, wherein a second conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the second conduit. 3011.The method of claim 3004, wherein a second conduit is disposed withinthe opening, the method further comprising removing an oxidation productfrom the formation through the second conduit and transferring heat fromthe oxidation product in the conduit to the oxidizing fluid in thesecond conduit.
 3012. The method of claim 3004, wherein a second conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the second conduit,wherein a flow rate of the oxidizing fluid in the second conduit isapproximately equal to a flow rate of the oxidation product in thesecond conduit.
 3013. The method of claim 3004, wherein a second conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the second conduit andcontrolling a pressure between the oxidizing fluid and the oxidationproduct in the second conduit to reduce contamination of the oxidationproduct by the oxidizing fluid.
 3014. The method of claim 3004, whereina second conduit is disposed within the opening, the method furthercomprising removing an oxidation product from the formation through theconduit and substantially inhibiting the oxidation product from flowinginto portions of the formation beyond the reaction zone.
 3015. Themethod of claim 3004, further comprising substantially inhibiting theoxidizing fluid from flowing into portions of the formation beyond thereaction zone.
 3016. The method of claim 3004, wherein a center conduitis disposed within an outer conduit, and wherein the outer conduit isdisposed within the opening, the method further comprising providing theoxidizing fluid into the opening through the center conduit and removingan oxidation product through the outer conduit.
 3017. The method ofclaim 3004, wherein the portion of the formation extends radially fromthe opening a width of less than approximately 0.2 m.
 3018. The methodof claim 3004, further comprising removing water from the formationprior to heating the portion.
 3019. The method of claim 3004, furthercomprising controlling the temperature of the formation to substantiallyinhibit production of oxides of nitrogen during oxidation.
 3020. Themethod of claim 3004, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3021. The method of claim 3004, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3022. The method of claim3004, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3023. The method of claim 3004, further comprising coupling anoverburden casing to the opening, wherein a packing material is disposedat a junction of the overburden casing and the opening.
 3024. A systemconfigured to heat a hydrocarbon containing formation, comprising: aninsulated conductor disposed in an opening in the formation, wherein theinsulated conductor is configured to provide heat to at least a portionof the formation during use; an oxidizing fluid source: a conduitdisposed in the opening wherein the conduit is configured to provide anoxidizing fluid from the oxidizing fluid source to a reaction zone inthe formation during use, and wherein the oxidizing fluid is selected tooxidize at least some hydrocarbons at the reaction zone during use suchthat heat is generated at the reaction zone; and wherein the system isconfigured to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 3025.The system of claim 3024, wherein the oxidizing fluid is configured togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 3026.The system of claim 3024, wherein the conduit comprises orifices, andwherein the orifices are configured to provide the oxidizing fluid intothe opening.
 3027. The system of claim 3024, wherein the conduitcomprises critical flow orifices, and wherein the critical flow orificesare configured to control a flow of the oxidizing fluid such that a rateof oxidation in the formation is controlled.
 3028. The system of claim3024, wherein the conduit is configured to be cooled with the oxidizingfluid such that the conduit is not substantially heated by oxidation.3029. The system of claim 3024, wherein the conduit is furtherconfigured to remove an oxidation product.
 3030. The system of claim3024, wherein the conduit is further configured to remove an oxidationproduct, and wherein the conduit is further configured such that theoxidation product transfers substantial heat to the oxidizing fluid.3031. The system of claim 3024, wherein the conduit is furtherconfigured to remove an oxidation product, and wherein a flow rate ofthe oxidizing fluid in the conduit is approximately equal to a flow rateof the oxidation product in the conduit.
 3032. The system of claim 3024,wherein the conduit is further configured to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the secondconduit and a pressure of the oxidation product in the conduit arecontrolled to reduce contamination of the oxidation product by theoxidizing fluid.
 3033. The system of claim 3024, wherein the conduit isfurther configured to remove an oxidation product, and wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone.
 3034. The system of claim3024, wherein the oxidizing fluid is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 3035.The system of claim 3024 further comprising a center conduit disposedwithin the conduit, wherein the center conduit is configured to providethe oxidizing fluid into the opening during use, and wherein the conduitis further configured to remove an oxidation product during use. 3036.The system of claim 3024 wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.3037. The system of claim 3024, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3038. The system of claim 3024, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3039. The system of claim3024, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3040. The system of claim 3024 further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3041. The system ofclaim 3024, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3042. The system of claim3024, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3043. The system of claim 3024, wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3044. A system configurable to heata hydrocarbon containing formation, comprising: an insulated conductorconfigurable to be disposed in an opening in the formation, wherein theinsulated conductor is further configurable to provide heat to at leasta portion of the formation during use; a conduit configurable to bedisposed in the opening, wherein the conduit is further configurable toprovide an oxidizing fluid from an oxidizing fluid source to a reactionzone in the formation during use, and wherein the system is configurableto allow the oxidizing fluid to oxidize at least some hydrocarbons atthe reaction zone during use such that heat is generated at the reactionzone; and wherein the system is further configurable to allow heat totransfer substantially by conduction from the reaction zone to apyrolysis zone of the formation during use.
 3045. The system of claim3044, wherein the oxidizing fluid is configurable to generate heat inthe reaction zone such that the oxidizing fluid is transported throughthe reaction zone substantially by diffusion.
 3046. The system of claim3044, wherein the conduit comprises orifices, and wherein the orificesare configurable to provide the oxidizing fluid into the opening. 3047.The system of claim 3044, wherein the conduit comprises critical floworifices, and wherein the critical flow orifices are configurable tocontrol a flow of the oxidizing fluid such that a rate of oxidation inthe formation is controlled.
 3048. The system of claim 3044, wherein theconduit is further configurable to be cooled with the oxidizing fluidsuch that the conduit is not substantially heated by oxidation. 3049.The system of claim 3044, wherein the conduit is further configurable toremove an oxidation product.
 3050. The system of claim 3044, wherein theconduit is further configurable to remove an oxidation product, suchthat the oxidation product transfers heat to the oxidizing fluid. 3051.The system of claim 3044, wherein the conduit is further configurable toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3052. The system of claim 3044,wherein the conduit is further configurable to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.3053. The system of claim 3044, wherein the conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3054. The system of claim 3044,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3055. The system ofclaim 3044, further comprising a center conduit disposed within theconduit, wherein center conduit is configurable to provide the oxidizingfluid into the opening during use, and wherein the conduit is furtherconfigurable to remove an oxidation product during use.
 3056. The systemof claim 3044, wherein the portion of the formation extends radiallyfrom the opening a width of less than approximately 0.2 m.
 3057. Thesystem of claim 3044, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3058. The system of claim 3044, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3059. The system of claim 3044,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3060. Thesystem of claim 3044, further comprising an overburden casing coupled tothe opening, wherein a packing material is disposed at a junction of theoverburden casing and the opening.
 3061. The system of claim 3044,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation,wherein a packing material is disposed at a junction of the overburdencasing and the opening, and wherein the packing material is configurableto substantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3062. The system of claim 3044, furthercomprising an overburden casing coupled to the opening wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3063. The system of claim 3044, wherein the system is furtherconfigurable such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3064. An in situ method for heatinga hydrocarbon containing formation, comprising: heating a portion of theformation to a temperature sufficient to support reaction ofhydrocarbons within the portion of the formation with an oxidizingfluid, wherein heating comprises applying an electrical current to aninsulated conductor to provide heat to the portion, and wherein theinsulated conductor is disposed within the opening; providing theoxidizing fluid to a reaction zone in the formation, allowing theoxidizing fluid to react with at least a portion of the hydrocarbons atthe reaction zone to generate heat at the reaction zone; andtransferring the generated heat substantially by conduction from thereaction zone to a pyrolysis zone in the formation.
 3065. The method ofclaim 3064, further comprising transporting the oxidizing fluid throughthe reaction zone by diffusion.
 3066. The method of claim 3064, furthercomprising directing at least a portion of the oxidizing fluid into theopening through orifices of a conduit disposed in the opening.
 3067. Themethod of claim 3064, further comprising controlling a flow of theoxidizing fluid with critical flow orifices of a conduit disposed in theopening such that a rate of oxidation is controlled.
 3068. The method ofclaim 3064, further comprising increasing a flow of the oxidizing fluidin the opening to accommodate an increase in a volume of the reactionzone such that a rate of oxidation is substantially constant over timewithin the reaction zone.
 3069. The method of claim 3064, wherein aconduit is disposed in the opening, the method further comprisingcooling the conduit with the oxidizing fluid to reduce heating of theconduit by oxidation.
 3070. The method of claim 3064, wherein a conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the conduit.
 3071. Themethod of claim 3064, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit and transferring heat from the oxidationproduct in the conduit to the oxidizing fluid in the conduit.
 3072. Themethod of claim 3064, wherein a conduit is disposed within the openingthe method further comprising removing an oxidation product from theformation through the conduit, wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3073. The method of claim 3064,wherein a conduit is disposed within the opening, the method furthercomprising removing an oxidation product from the formation through theconduit and controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 3074. The method of claim3064, wherein a conduit is disposed within the opening the methodfurther comprising removing an oxidation product from the formationthrough the conduit and substantially inhibiting the oxidation productfrom flowing into portions of the formation beyond the reaction zone.3075. The method of claim 3064, further comprising substantiallyinhibiting the oxidizing fluid from flowing into portions of theformation beyond the reaction zone.
 3076. The method of claim 3064wherein a center conduit is disposed within an outer conduit, andwherein the outer conduit is disposed within the opening, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theouter conduit.
 3077. The method of claim 3064, wherein the portion ofthe formation extends radially from the opening a width of less thanapproximately 0.2 m.
 3078. The method of claim 3064, further comprisingremoving water from the formation prior to heating the portion. 3079.The method of claim 3064, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 3080. The method of claim 3064, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3081.The method of claim 3064, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3082. The method of claim 3064, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3083. The method of claim 3064,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 3084. The method of claim 3064, wherein the pyrolysiszone is substantially adjacent to the reaction zone.
 3085. An in situmethod for heating a hydrocarbon containing formation, comprising:heating a portion of the formation to a temperature sufficient tosupport reaction of hydrocarbons within the portion of the formationwith an oxidizing fluid, wherein the portion is located substantiallyadjacent to an opening in the formation, wherein heating comprisesapplying an electrical current to an insulated conductor to provide heatto the portion, wherein the insulated conductor is coupled to a conduit,wherein the conduit comprises critical flow orifices, and wherein theconduit is disposed within the opening; providing the oxidizing fluid toa reaction zone in the formation; allowing the oxidizing fluid to reactwith at least a portion of the hydrocarbons at the reaction zone togenerate heat at the reaction zone; and transferring the generated heatsubstantially by conduction from the reaction zone to a pyrolysis zonein the formation.
 3086. The method of claim 3085, further comprisingtransporting the oxidizing fluid through the reaction zone by diffusion.3087. The method of claim 3085, further comprising controlling a flow ofthe oxidizing fluid with the critical flow orifices such that a rate ofoxidation is controlled.
 3088. The method of claim 3085, furthercomprising increasing a flow of the oxidizing fluid in the opening toaccommodate an increase in a volume of the reaction zone such that arate of oxidation is substantially constant over time within thereaction zone.
 3089. The method of claim 3085 further comprising coolingthe conduit with the oxidizing fluid to reduce heating of the conduit byoxidation.
 3090. The method of claim 3085, further comprising removingan oxidation product from the formation through the conduit.
 3091. Themethod of claim 3085, further comprising removing an oxidation productfrom the formation through the conduit and transferring heat from theoxidation product in the conduit to the oxidizing fluid in the conduit.3092. The method of claim 3085, further comprising removing an oxidationproduct from the formation through the conduit, wherein a flow rate ofthe oxidizing fluid in the conduit is approximately equal to a flow rateof the oxidation product in the conduit.
 3093. The method of claim 3085,further comprising removing an oxidation product from the formationthrough the conduit and controlling a pressure between the oxidizingfluid and the oxidation product in the conduit to reduce contaminationof the oxidation product by the oxidizing fluid.
 3094. The method ofclaim 3085, further comprising removing an oxidation product from theformation through the conduit and substantially inhibiting the oxidationproduct from flowing into portions of the formation beyond the reactionzone.
 3095. The method of claim 3085, further comprising substantiallyinhibiting the oxidizing fluid from flowing into portions of theformation beyond the reaction zone.
 3096. The method of claim 3085,wherein a center conduit is disposed within the conduit, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theconduit.
 3097. The method of claim 3085, wherein the portion of theformation extends radially from the opening a width of less thanapproximately 0.2 m.
 3098. The method of claim 3085, further comprisingremoving water from the formation prior to heating the portion. 3099.The method of claim 3085, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 3100. The method of claim 3085, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3101.The method of claim 3085, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3102. The method of claim 3085, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3103. The method of claim 3085,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 3104. The method of claim 3085, wherein the pyrolysiszone is substantially adjacent to the reaction zone.
 3105. A systemconfigured to heat a hydrocarbon containing formation, comprising: atleast one elongated member disposed in an opening in the formation,wherein at least the one elongated member is configured to provide heatto at least a portion of the formation during use; an oxidizing fluidsource; a conduit disposed in the opening, wherein the conduit isconfigured to provide an oxidizing fluid from the oxidizing fluid sourceto a reaction zone in the formation during use, and wherein theoxidizing fluid is selected to oxidize at least some hydrocarbons at thereaction zone during use such that heat is generated at the reactionzone; and wherein the system is configured to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 3106. The system of claim 3105, wherein theoxidizing fluid is configured to generate heat in the reaction zone suchthat the oxidizing fluid is transported through the reaction zonesubstantially by diffusion.
 3107. The system of claim 3105, wherein theconduit comprises orifices, and wherein the orifices are configured toprovide the oxidizing fluid into the opening.
 3108. The system of claim3105, wherein the conduit comprises critical flow orifices, and whereinthe critical flow orifices are configured to control a flow of theoxidizing fluid such that a rate of oxidation in the formation iscontrolled.
 3109. The system of claim 3105, wherein the conduit isfurther configured to be cooled with the oxidizing fluid such that theconduit is not substantially heated by oxidation.
 3110. The system ofclaim 3105, wherein the conduit is further configured to remove anoxidation product.
 3111. The system of claim 3105, wherein the conduitis further configured to remove an oxidation product such that theoxidation product transfers heat to the oxidizing fluid.
 3112. Thesystem of claim 3105, wherein the conduit is further configured toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3113. The system of claim 3105,wherein the conduit is further configured to remove an oxidation productand wherein a pressure of the oxidizing fluid in the conduit and apressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.3114. The system of claim 3105, wherein the conduit is furtherconfigured to remove an oxidation product and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3115. The system of claim 3105,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3116. The system ofclaim 3105, further comprising a center conduit disposed within theconduit wherein the center conduit is configured to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configured to remove an oxidation product during use.
 3117. Thesystem of claim 3105, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.3118. The system of claim 3105, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3119. The system of claim 3105, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3120. The system of claim3105, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3121. The system of claim 3105, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3122. The system ofclaim 3105, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3123. The system of claim3105, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3124. The system of claim 3105 wherein the system isfurther configured such that transferred heat can pyrolyze at least somehydrocarbons in the pyrolysis zone.
 3125. A system configurable to heata hydrocarbon containing formation, comprising: at least one elongatedmember configurable to be disposed in an opening in the formation,wherein at least the one elongated member is further configurable toprovide heat to at least a portion of the formation during use; aconduit configurable to be disposed in the opening, wherein the conduitis further configurable to provide an oxidizing fluid from the oxidizingfluid source to a reaction zone in the formation during use, and whereinthe system is configurable to allow the oxidizing fluid to oxidize atleast some hydrocarbons at the reaction zone during use such that heatis generated at the reaction zone; and wherein the system is furtherconfigurable to allow heat to transfer substantially by conduction fromthe reaction zone to a pyrolysis zone of the formation during use. 3126.The system of claim 3125, wherein the oxidizing fluid is configurable togenerate heat in the reaction zone such that the oxidizing fluid istransported through the reaction zone substantially by diffusion. 3127.The system of claim 3125, wherein the conduit comprises orifices, andwherein the orifices are configurable to provide the oxidizing fluidinto the opening.
 3128. The system of claim 3125, wherein the conduitcomprises critical flow orifices, and wherein the critical flow orificesare configurable to control a flow of the oxidizing fluid such that arate of oxidation in the formation is controlled.
 3129. The system ofclaim 3125, wherein the conduit is further configurable to be cooledwith the oxidizing fluid such that the conduit is not substantiallyheated by oxidation.
 3130. The system of claim 3125, wherein the conduitis further configurable to remove an oxidation product.
 3131. The systemof claim 3125 wherein the conduit is further configurable to remove anoxidation product such that the oxidation product transfers heat to theoxidizing fluid.
 3132. The system of claim 3125, wherein the conduit isfurther configurable to remove an oxidation product, and wherein a flowrate of the oxidizing fluid in the conduit is approximately equal to aflow rate of the oxidation product in the conduit.
 3133. The system ofclaim 3125, wherein the conduit is further configurable to remove anoxidation product, and wherein a pressure of the oxidizing fluid in theconduit and a pressure of the oxidation product in the conduit arecontrolled to reduce contamination of the oxidation product by theoxidizing fluid.
 3134. The system of claim 3125, wherein the conduit isfurther configurable to remove an oxidation product, and wherein theoxidation product is substantially inhibited from flowing into portionsof the formation beyond the reaction zone.
 3135. The system of claim3125, wherein the oxidizing fluid is substantially inhibited fromflowing into portions of the formation beyond the reaction zone. 3136.The system of claim 3125, further comprising a center conduit disposedwithin the conduit, wherein center conduit is configurable to providethe oxidizing fluid into the opening during use, and wherein the conduitis further configurable to remove an oxidation product during use. 3137.The system of claim 3125, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.3138. The system of claim 3125, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3139. The system of claim 3125, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3140. The system of claim3125, further comprising an overburden casing coupled to the openingwherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3141. The system of claim 3125, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3142. The system ofclaim 3125, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3143. The system of claim3125, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3144. The system of claim 3125, wherein the system isfurther configurable such that transferred heat can pyrolyze at leastsome hydrocarbons in the pyrolysis zone.
 3145. An in situ method forheating a hydrocarbon containing formation, comprising: heating aportion of the formation to a temperature sufficient to support reactionof hydrocarbons within the portion of the formation with an oxidizingfluid, wherein heating comprises applying an electrical current to atleast one elongated member to provide heat to the portion, and whereinat least the one elongated member is disposed within the opening;providing the oxidizing fluid to a reaction zone in the formation;allowing the oxidizing fluid to react with at least a portion of thehydrocarbons at the reaction zone to generate heat at the reaction zone;and transferring the generated heat substantially by conduction from thereaction zone to a pyrolysis zone in the formation.
 3146. The method ofclaim 3145, further comprising transporting the oxidizing fluid throughthe reaction zone by diffusion.
 3147. The method of claim 3145, furthercomprising directing at least a portion of the oxidizing fluid into theopening through orifices of a conduit disposed in the opening.
 3148. Themethod of claim 3145, further comprising controlling a flow of theoxidizing fluid with critical flow orifices of a conduit disposed in theopening such that a rate of oxidation is controlled.
 3149. The method ofclaim 3145, further comprising increasing a flow of the oxidizing fluidin the opening to accommodate an increase in a volume of the reactionzone such that a rate of oxidation is substantially constant over timewithin the reaction zone.
 3150. The method of claim 3145, wherein aconduit is disposed in the opening, the method further comprisingcooling the conduit with the oxidizing fluid to reduce heating of theconduit by oxidation.
 3151. The method of claim 3145, wherein a conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the conduit.
 3152. Themethod of claim 3145, wherein a conduit is disposed within the openingthe method further comprising removing an oxidation product from theformation through the conduit and transferring heat from the oxidationproduct in the conduit to the oxidizing fluid in the conduit.
 3153. Themethod of claim 3145, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit, wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3154. The method of claim 3145,wherein a conduit is disposed within the opening the method furthercomprising removing an oxidation product from the formation through theconduit and controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 3155. The method of claim3145, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit and substantially inhibiting the oxidation productfrom flowing into portions of the formation beyond the reaction zone.3156. The method of claim 3145, further comprising substantiallyinhibiting the oxidizing fluid from flowing into portions of theformation beyond the reaction zone.
 3157. The method of claim 3145,wherein a center conduit is disposed within an outer conduit, andwherein the outer conduit is disposed within the opening, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theouter conduit.
 3158. The method of claim 3145, wherein the portion ofthe formation extends radially from the opening a width of less thanapproximately 0.2 m.
 3159. The method of claim 3145, further comprisingremoving water from the formation prior to heating the portion. 3160.The method of claim 3145, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 3161. The method of claim 3145, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3162.The method of claim 3145, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3163. The method of claim 3145, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing, is further disposed in cement.
 3164. The method of claim 3145,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 3165. The method of claim 3145, wherein the pyrolysiszone is substantially adjacent to the reaction zone.
 3166. A systemconfigured to heat a hydrocarbon containing formation, comprising: aheat exchanger disposed external to the formation, wherein the heatexchanger is configured to heat an oxidizing fluid during use; a conduitdisposed in the opening, wherein the conduit is configured to providethe heated oxidizing fluid from the heat exchanger to at least a portionof the formation during use, wherein the system is configured to allowheat to transfer from the heated oxidizing fluid to at least the portionof the formation during use, and wherein the oxidizing fluid is selectedto oxidize at least some hydrocarbons at a reaction zone in theformation during use such that heat is generated at the reaction zone;and wherein the system is configured to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 3167. The system of claim 3166, wherein theoxidizing fluid is configured to generate heat in the reaction zone suchthat the oxidizing fluid is transported through the reaction zonesubstantially by diffusion.
 3168. The system of claim 3166, wherein theconduit comprises orifices, and wherein the orifices are configured toprovide the oxidizing fluid into the opening.
 3169. The system of claim3166, wherein the conduit comprises critical flow orifices, and whereinthe critical flow orifices are configured to control a flow of theoxidizing fluid such that a rate of oxidation in the formation iscontrolled.
 3170. The system of claim 3166, wherein the conduit isfurther configured to be cooled with the oxidizing fluid such that theconduit is not substantially heated by oxidation.
 3171. The system ofclaim 3166, wherein the conduit is further configured to remove anoxidation product.
 3172. The system of claim 3166, wherein the conduitis further configured to remove an oxidation product, such that theoxidation product transfers heat to the oxidizing fluid.
 3173. Thesystem of claim 3166, wherein the conduit is further configured toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3174. The system of claim 3166,wherein the conduit is further configured to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.3175. The system of claim 3166, wherein the conduit is furtherconfigured to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3176. The system of claim 3166,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3177. The system ofclaim 3166, further comprising a center conduit disposed within theconduit, wherein the center conduit is configured to provide theoxidizing fluid into the opening during use, and wherein the conduit isfurther configured to remove an oxidation product during use.
 3178. Thesystem of claim 3166, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.3179. The system of claim 3166, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3180. The system of claim 3166, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3181. The system of claim3166, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3182. The system of claim 3166, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3183. The system ofclaim 3166, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3184. The system of claim3166, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3185. A system configurable to heat a hydrocarboncontaining formation, comprising: a heat exchanger configurable to bedisposed external to the formation, wherein the heat exchanger isfurther configurable to heat an oxidizing fluid during use; a conduitconfigurable to be disposed in the opening, wherein the conduit isfurther configurable to provide the heated oxidizing fluid from the heatexchanger to at least a portion of the formation during use, wherein thesystem is configurable to allow heat to transfer from the heatedoxidizing fluid to at least the portion of the formation during use, andwherein the system is further configurable to allow the oxidizing fluidto oxidize at least some hydrocarbons at a reaction zone in theformation during use such that heat is generated at the reaction zone;and wherein the system is further configurable to allow heat to transfersubstantially by conduction from the reaction zone to a pyrolysis zoneof the formation during use.
 3186. The system of claim 3185, wherein theoxidizing fluid is configurable to generate heat in the reaction zonesuch that the oxidizing fluid is transported through the reaction zonesubstantially by diffusion.
 3187. The system of claim 3185, wherein theconduit comprises orifices, and wherein the orifices are configurable toprovide the oxidizing fluid into the opening.
 3188. The system of claim3185, wherein the conduit comprises critical flow orifices, and whereinthe critical flow orifices are configurable to control a flow of theoxidizing fluid such that a rate of oxidation in the formation iscontrolled.
 3189. The system of claim 3185, wherein the conduit isfurther configurable to be cooled with the oxidizing fluid such that theconduit is not substantially heated by oxidation.
 3190. The system ofclaim 3185, wherein the conduit is further configurable to remove anoxidation product.
 3191. The system of claim 3185, wherein the conduitis further configurable to remove an oxidation product such that theoxidation product transfers heat to the oxidizing fluid.
 3192. Thesystem of claim 3185, wherein the conduit is further configurable toremove an oxidation product, and wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3193. The system of claim 3185,wherein the conduit is further configurable to remove an oxidationproduct, and wherein a pressure of the oxidizing fluid in the conduitand a pressure of the oxidation product in the conduit are controlled toreduce contamination of the oxidation product by the oxidizing fluid.3194. The system of claim 3185, wherein the conduit is furtherconfigurable to remove an oxidation product, and wherein the oxidationproduct is substantially inhibited from flowing into portions of theformation beyond the reaction zone.
 3195. The system of claim 3185,wherein the oxidizing fluid is substantially inhibited from flowing intoportions of the formation beyond the reaction zone.
 3196. The system ofclaim 3185, further comprising a center conduit disposed within theconduit, wherein center conduit is configurable to provide the oxidizingfluid into the opening during use, and wherein the second conduit isfurther configurable to remove an oxidation product during use. 3197.The system of claim 3185, wherein the portion of the formation extendsradially from the opening a width of less than approximately 0.2 m.3198. The system of claim 3185, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3199. The system of claim 3185, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3200. The system of claim3185 further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3201. The system of claim 3185, further comprising an overburdencasing coupled to the opening, wherein a packing material is disposed ata junction of the overburden casing and the opening.
 3202. The system ofclaim 3185, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3203. The system of claim3185, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3204. An in situ method for heating a hydrocarboncontaining formation, comprising: heating a portion of the formation toa temperature sufficient to support reaction of hydrocarbons within theportion of the formation with an oxidizing fluid, wherein heatingcomprises: heating the oxidizing fluid with a heat exchanger, whereinthe heat exchanger is disposed external to the formation; providing theheated oxidizing fluid from the heat exchanger to the portion of theformation, and allowing heat to transfer from the heated oxidizing fluidto the portion of the formation; providing the oxidizing fluid to areaction zone in the formation; allowing the oxidizing fluid to reactwith at least a portion of the hydrocarbons at the reaction zone togenerate heat at the reaction zone; and transferring the generated heatsubstantially by conduction from the reaction zone to a pyrolysis zonein the formation.
 3205. The method of claim 3204, further comprisingtransporting the oxidizing fluid through the reaction zone by diffusion.3206. The method of claim 3204, further comprising directing at least aportion of the oxidizing fluid into the opening through orifices of aconduit disposed in the opening.
 3207. The method of claim 3204, furthercomprising controlling a flow of the oxidizing fluid with critical floworifices of a conduit disposed in the opening such that a rate ofoxidation is controlled.
 3208. The method of claim 3204, furthercomprising increasing a flow of the oxidizing fluid in the opening toaccommodate an increase in a volume of the reaction zone such that arate of oxidation is substantially constant over time within thereaction zone.
 3209. The method of claim 3204, wherein a conduit isdisposed in the opening, the method further comprising cooling theconduit with the oxidizing fluid to reduce heating of the conduit byoxidation.
 3210. The method of claim 3204, wherein a conduit is disposedwithin the opening, the method further comprising removing an oxidationproduct from the formation through the conduit.
 3211. The method ofclaim 3204, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit and transferring heat from the oxidation product inthe conduit to the oxidizing fluid in the conduit.
 3212. The method ofclaim 3204, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit, wherein a flow rate of the oxidizing fluid in theconduit is approximately equal to a flow rate of the oxidation productin the conduit.
 3213. The method of claim 3204, wherein a conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the conduit and controllinga pressure between the oxidizing fluid and the oxidation product in theconduit to reduce contamination of the oxidation product by theoxidizing fluid.
 3214. The method of claim 3204, wherein a conduit isdisposed within the opening, the method further comprising removing anoxidation product from the formation through the conduit andsubstantially inhibiting the oxidation product from flowing intoportions of the formation beyond the reaction zone.
 3215. The method ofclaim 3204, further comprising substantially inhibiting the oxidizingfluid from flowing into portions of the formation beyond the reactionzone.
 3216. The method of claim 3204, wherein a center conduit isdisposed within an outer conduit, and wherein the outer conduit isdisposed within the opening, the method further comprising providing theoxidizing fluid into the opening through the center conduit and removingan oxidation product through the outer conduit.
 3217. The method ofclaim 3204, wherein the portion of the formation extends radially fromthe opening a width of less than approximately 0.2 m.
 3218. The methodof claim 3204 further comprising removing water from the formation priorto heating the portion.
 3219. The method of claim 3204, furthercomprising controlling the temperature of the formation to substantiallyinhibit production of oxides of nitrogen during oxidation.
 3220. Themethod of claim 3204, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3221. The method of claim 3204, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3222. The method of claim3204, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3223. The method of claim 3204, further comprising coupling anoverburden casing to the opening, wherein a packing material is disposedat a junction of the overburden casing and the opening.
 3224. The methodof claim 3204, wherein the pyrolysis zone is substantially adjacent tothe reaction zone.
 3225. An in situ method for heating a hydrocarboncontaining formation, comprising: heating a portion of the formation toa temperature sufficient to support reaction of hydrocarbons within theportion of the formation with an oxidizing fluid, wherein heatingcomprises: oxidizing a fuel gas in a heater, wherein the heater isdisposed external to the formation; providing the oxidized fuel gas fromthe heater to the portion of the formation; and allowing heat totransfer from the oxidized fuel gas to the portion of the formation;providing the oxidizing fluid to a reaction zone in the formation;allowing the oxidizing fluid to react with at least a portion of thehydrocarbons at the reaction zone to generate heat at the reaction zone;and transferring the generated heat substantially by conduction from thereaction zone to a pyrolysis zone in the formation.
 3226. The method ofclaim 3225, further comprising transporting the oxidizing fluid throughthe reaction zone by diffusion.
 3227. The method of claim 3225, furthercomprising directing at least a portion of the oxidizing fluid into theopening through orifices of a conduit disposed in the opening.
 3228. Themethod of claim 3225, further comprising controlling a flow of theoxidizing fluid with critical flow orifices of a conduit disposed in theopening such that a rate of oxidation is controlled.
 3229. The method ofclaim 3225, further comprising increasing a flow of the oxidizing fluidin the opening to accommodate an increase in a volume of the reactionzone such that a rate of oxidation is substantially constant over timewithin the reaction zone.
 3230. The method of claim 3225, wherein aconduit is disposed in the opening, the method further comprisingcooling the conduit with the oxidizing fluid to reduce heating of theconduit by oxidation.
 3231. The method of claim 3225, wherein a conduitis disposed within the opening, the method further comprising removingan oxidation product from the formation through the conduit.
 3232. Themethod of claim 3225 wherein a conduit is disposed within the openingthe method further comprising removing an oxidation product from theformation through the conduit and transferring heat from the oxidationproduct in the conduit to the oxidizing fluid in the conduit.
 3233. Themethod of claim 3225, wherein a conduit is disposed within the opening,the method further comprising removing an oxidation product from theformation through the conduit, wherein a flow rate of the oxidizingfluid in the conduit is approximately equal to a flow rate of theoxidation product in the conduit.
 3234. The method of claim 3225,wherein a conduit is disposed within the opening, the method furthercomprising removing an oxidation product from the formation through theconduit and controlling a pressure between the oxidizing fluid and theoxidation product in the conduit to reduce contamination of theoxidation product by the oxidizing fluid.
 3235. The method of claim3225, wherein a conduit is disposed within the opening, the methodfurther comprising removing an oxidation product from the formationthrough the conduit and substantially inhibiting the oxidation productfrom flowing into portions of the formation beyond the reaction zone.3236. The method of claim 3225, further comprising substantiallyinhibiting the oxidizing fluid from flowing into portions of theformation beyond the reaction zone.
 3237. The method of claim 3225,wherein a center conduit is disposed within an outer conduit, andwherein the outer conduit is disposed within the opening, the methodfurther comprising providing the oxidizing fluid into the openingthrough the center conduit and removing an oxidation product through theouter conduit.
 3238. The method of claim 3225, wherein the portion ofthe formation extends radially from the opening a width of less thanapproximately 0.2 m.
 3239. The method of claim 3225, further comprisingremoving water from the formation prior to heating the portion. 3240.The method of claim 3225, further comprising controlling the temperatureof the formation to substantially inhibit production of oxides ofnitrogen during oxidation.
 3241. The method of claim 3225, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3242.The method of claim 3225, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3243. The method of claim 3225, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasino is further disposed in cement.
 3244. The method of claim 3225,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casingand the opening.
 3245. The method of claim 3225, wherein the pyrolysiszone is substantially adjacent to the reaction zone.
 3246. A systemconfigured to heat a hydrocarbon containing formation, comprising: aninsulated conductor disposed within an open wellbore in the formation,wherein the insulated conductor is configured to provide radiant heat toat least a portion of the formation during use; and wherein the systemis configured to allow heat to transfer from the insulated conductor toa selected section of the formation during use.
 3247. The system ofclaim 3246, wherein the insulated conductor is further configured togenerate heat during application of an electrical current to theinsulated conductor during use.
 3248. The system of claim 3246, furthercomprising a support member, wherein the support member is configured tosupport the insulated conductor.
 3249. The system of claim 3246 furthercomprising a support member and a centralizer, wherein the supportmember is configured to support the insulated conductor, and wherein thecentralizer is configured to maintain a location of the insulatedconductor on the support member.
 3250. The system of claim 3246, whereinthe open wellbore comprises a diameter of at least approximately 5 cm.3251. The system of claim 3246, further comprising a lead-in conductorcoupled to the insulated conductor wherein the lead-in conductorcomprises a low resistance conductor configured to generatesubstantially no heat.
 3252. The system of claim 3246, furthercomprising a lead-in conductor coupled to the insulated conductor,wherein the lead-in conductor comprises a rubber insulated conductor.3253. The system of claim 3246, further comprising a lead-in conductorcoupled to the insulated conductor, wherein the lead-in conductorcomprises a copper wire.
 3254. The system of claim 3246, furthercomprising a lead-in conductor coupled to the insulated conductor with acold pin transition conductor.
 3255. The system of claim 3246, furthercomprising a lead-in conductor coupled to the insulated conductor with acold pin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3256. Thesystem of claim 3246, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material is disposed in a sheath.
 3257. Thesystem of claim 3246, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe conductor comprises a copper-nickel alloy.
 3258. The system of claim3246, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 7% nickel by weight to approximately 12% nickel by weight.3259. The system of claim 3246, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the conductor comprises a copper-nickel alloy, and wherein thecopper-nickel alloy comprises approximately 2% nickel by weight toapproximately 6% nickel by weight.
 3260. The system of claim 3246,wherein the insulated conductor comprises a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises a thermally conductive material.
 3261. Thesystem of claim 3246, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises magnesium oxide. 3262.The system of claim 3246, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, wherein theelectrically insulating material comprises magnesium oxide, and whereinthe magnesium oxide comprises a thickness of at least approximately 1mm.
 3263. The system of claim 3246, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises aluminumoxide and magnesium oxide.
 3264. The system of claim 3246, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, wherein the magnesium oxide comprises grainparticles, and wherein the grain particles are configured to occupyporous spaces within the magnesium oxide.
 3265. The system of claim3246, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3266. The system of claim3246, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises stainless steel.
 3267. The system of claim 3246, furthercomprising two additional insulated conductors, wherein the insulatedconductor and the two additional insulated conductors are configured ina 3-phase Y configuration.
 3268. The system of claim 3246, furthercomprising an additional insulated conductor, wherein the insulatedconductor and the additional insulated conductor are coupled to asupport member, and wherein the insulated conductor and the additionalinsulated conductor are configured in a series electrical configuration.3269. The system of claim 3246, further comprising an additionalinsulated conductor, wherein the insulated conductor and the additionalinsulated conductor are coupled to a support member, and wherein theinsulated conductor and the additional insulated conductor areconfigured in a parallel electrical configuration.
 3270. The system ofclaim 3246, wherein the insulated conductor is configured to generateradiant heat of approximately 500 W/m to approximately 1150 W/m duringuse.
 3271. The system of claim 3246, further comprising a support memberconfigured to support the insulated conductor, wherein the supportmember comprises orifices configured to provide fluid flow through thesupport member into the open wellbore during use.
 3272. The system ofclaim 3246, further comprising a support member configured to supportthe insulated conductor, wherein the support member comprises criticalflow orifices configured to provide a substantially constant amount offluid flow through the support member into the open wellbore during use.3273. The system of claim 3246, further comprising a tube coupled to theinsulated conductor, wherein the tube is configured to provide a flow offluid into the open wellbore during use.
 3274. The system of claim 3246,further comprising a tube coupled to the insulated conductor, whereinthe tube comprises critical flow orifices configured to provide asubstantially constant amount of fluid flow through the support memberinto the open wellbore during use.
 3275. The system of claim 3246,further comprising an overburden casing coupled to the open wellbore,wherein the overburden casing is disposed in an overburden of theformation.
 3276. The system of claim 3246, further comprising anoverburden casing coupled to the open wellbore wherein the overburdencasing is disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3277. The system of claim 3246,further comprising an overburden casing coupled to the open wellbore,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3278. The system of claim 3246, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation and wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore.
 3279. The system of claim 3246, further comprising anoverburden casing coupled to the open wellbore, wherein the overburdencasing is disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore, and wherein the packing material is configured tosubstantially inhibit a flow of fluid between the open wellbore and theoverburden casing during use.
 3280. The system of claim 3246, furthercomprising an overburden casing coupled to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation,wherein a packing material is disposed at a junction of the overburdencasing and the open wellbore, and wherein the packing material comprisescement.
 3281. The system of claim 3246, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigured to couple to the lead-in conductor.
 3282. The system of claim3246, wherein the system is further configured to transfer heat suchthat the transferred heat can pyrolyze at least some of the hydrocarbonsin the selected section.
 3283. A system configurable to heat ahydrocarbon containing formation, comprising: an insulated conductorconfigurable to be disposed within an open wellbore in the formation,wherein the insulated conductor is further configurable to provideradiant heat to at least a portion of the formation during use; andwherein the system is configurable to allow heat to transfer from theinsulated conductor to a selected section of the formation during use.3284. The system of claim 3283, wherein the insulated conductor isfurther configurable to generate heat during application of anelectrical current to the insulated conductor during use.
 3285. Thesystem of claim 3283, further comprising a support member, wherein thesupport member is configurable to support the insulated conductor. 3286.The system of claim 3283, further comprising a support member and acentralizer, wherein the support member is configurable to support theinsulated conductor, and wherein the centralizer is configurable tomaintain a location of the insulated conductor on the support member.3287. The system of claim 3283, wherein the open wellbore comprises adiameter of at least approximately 5 cm.
 3288. The system of claim 3283,further comprising a lead-in conductor coupled to the insulatedconductor, wherein the lead-in conductor comprises a low resistanceconductor configurable to generate substantially no heat.
 3289. Thesystem of claim 3283, further comprising a lead-in conductor coupled tothe insulated conductor, wherein the lead-in conductor comprises arubber insulated conductor.
 3290. The system of claim 3283, furthercomprising a lead-in conductor coupled to the insulated conductor,wherein the lead-in conductor comprises a copper wire.
 3291. The systemof claim 3283, further comprising a lead-in conductor coupled to theinsulated conductor with a cold pin transition conductor.
 3292. Thesystem of claim 3283, further comprising a lead-in conductor coupled tothe insulated conductor with a cold pin transition conductor, whereinthe cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 3293. The system of claim 3283, whereinthe insulated conductor comprises a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath.
 3294. The system of claim3283, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material and wherein the conductor comprisesa copper-nickel alloy.
 3295. The system of claim 3283, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, wherein the conductor comprises a copper-nickelalloy, and wherein the copper-nickel alloy comprises approximately 7%nickel by weight to approximately 12% nickel by weight.
 3296. The systemof claim 3283, wherein the insulated conductor comprises a conductordisposed in an electrically insulating material, wherein the conductorcomprises a copper-nickel alloy, and wherein the copper-nickel alloycomprises approximately 2% nickel by weight to approximately 6% nickelby weight.
 3297. The system of claim 3283, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, and wherein the electrically insulating material comprises athermally conductive material.
 3298. The system of claim 3283, whereinthe insulated conductor comprises a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises magnesium oxide.
 3299. The system of claim3283, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, and wherein the magnesium oxidecomprises a thickness of at least approximately 1 mm.
 3300. The systemof claim 3283, wherein the insulated conductor comprises a conductordisposed in an electrically insulating material, and wherein theelectrically insulating material comprises aluminum oxide and magnesiumoxide.
 3301. The system of claim 3283, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,wherein the magnesium oxide comprises grain particles, and wherein thegrain particles are configurable to occupy porous spaces within themagnesium oxide.
 3302. The system of claim 3283, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, and wherein the electrically insulating material is disposedin a sheath, and wherein the sheath comprises a corrosion-resistantmaterial.
 3303. The system of claim 3283, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, and wherein the electrically insulating material is disposedin a sheath, and wherein the sheath comprises stainless steel.
 3304. Thesystem of claim 3283, further comprising two additional insulatedconductors, wherein the insulated conductor and the two additionalinsulated conductors are configurable in a 3-phase Y configuration.3305. The system of claim 3283, further comprising an additionalinsulated conductor, wherein the insulated conductor and the additionalinsulated conductor are coupled to a support member, and wherein theinsulated conductor and the additional insulated conductor areconfigurable in a series electrical configuration.
 3306. The system ofclaim 3283, further comprising an additional insulated conductor,wherein the insulated conductor and the additional insulated conductorare coupled to a support member, and wherein the insulated conductor andthe additional insulated conductor are configurable in a parallelelectrical configuration.
 3307. The system of claim 3283, wherein theinsulated conductor is configurable to generate radiant heat ofapproximately 500 W/m to approximately 1150 W/m during use.
 3308. Thesystem of claim 3283, further comprising a support member configurableto support the insulated conductor, wherein the support member comprisesorifices configurable to provide fluid flow through the support memberinto the open wellbore during use.
 3309. The system of claim 3283,further comprising a support member configurable to support theinsulated conductor, wherein the support member comprises critical floworifices configurable to provide a substantially constant amount offluid flow through the support member into the open wellbore during use.3310. The system of claim 3283, further comprising a tube coupled to theinsulated conductor, wherein the tube is configurable to provide a flowof fluid into the open wellbore during use.
 3311. The system of claim3283, further comprising a tube coupled to the first insulatedconductor, wherein the tube comprises critical flow orificesconfigurable to provide a substantially constant amount of fluid flowthrough the support member into the open wellbore during use.
 3312. Thesystem of claim 3283, further comprising an overburden casing coupled tothe open wellbore, wherein the overburden casing is disposed in anoverburden of the formation.
 3313. The system of claim 3283, furthercomprising an overburden casing coupled to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3314. The system of claim3283, further comprising an overburden casing coupled to the openwellbore, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing is further disposed incement.
 3315. The system of claim 3283, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore.
 3316. The system of claim 3283, further comprising anoverburden casing coupled to the open wellbore, wherein the overburdencasing is disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and the openwellbore, and wherein the packing material is configurable tosubstantially inhibit a flow of fluid between the open wellbore and theoverburden casing during use.
 3317. The system of claim 3283, furthercomprising an overburden casing coupled to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation,wherein a packing material is disposed at a junction of the overburdencasing and the open wellbore, and wherein the packing material comprisescement.
 3318. The system of claim 3283, further comprising an overburdencasing coupled to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigurable to couple to the lead-in conductor.
 3319. The system ofclaim 3283 wherein the system is further configured to transfer heatsuch that the transferred heat can pyrolyze at least some hydrocarbonsin the selected section.
 3320. An in situ method for heating ahydrocarbon containing formation, comprising: applying an electricalcurrent to an insulated conductor to provide radiant heat to at least aportion of the formation, wherein the insulated conductor is disposedwithin an open wellbore in the formation; and allowing the radiant heatto transfer from the insulated conductor to a selected section of theformation.
 3321. The method of claim 3320, further comprising supportingthe insulated conductor on a support member.
 3322. The method of claim3320 further comprising supporting the insulated conductor on a supportmember and maintaining a location of the insulated conductor on thesupport member with a centralizer.
 3323. The method of claim 3320,wherein the insulated conductor is coupled to two additional insulatedconductors, wherein the insulated conductor and the two insulatedconductors are disposed within the open wellbore, and wherein the threeinsulated conductors are electrically coupled in a 3-phase Yconfiguration.
 3324. The method of claim 3320, wherein an additionalinsulated conductor is disposed within the open wellbore.
 3325. Themethod of claim 3320, wherein an additional insulated conductor isdisposed within the open wellbore, and wherein the insulated conductorand the additional insulated conductor are electrically coupled in aseries configuration.
 3326. The method of claim 3320, wherein anadditional insulated conductor is disposed within the open wellbore, andwherein the insulated conductor and the additional insulated conductorare electrically coupled in a parallel configuration.
 3327. The methodof claim 3320, wherein the provided heat comprises approximately 500 W/mto approximately 1150 W/m.
 3328. The method of claim 3320, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, and wherein the conductor comprises a copper-nickelalloy.
 3329. The method of claim 3320, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the conductor comprises a copper-nickel alloy, and wherein thecopper-nickel alloy comprises approximately 7% nickel by weight toapproximately 12% nickel by weight.
 3330. The method of claim 3320wherein the insulated conductor comprises a conductor disposed in anelectrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 2% nickel by weight to approximately 6% nickel by weight.3331. The method of claim 3320, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises magnesiumoxide.
 3332. The method of claim 3320, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,and wherein the magnesium oxide comprises a thickness of at leastapproximately 1 mm.
 3333. The method of claim 3320, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, and wherein the electrically insulating materialcomprises aluminum oxide and magnesium oxide.
 3334. The method of claim3320, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the electrically insulatingmaterial comprises magnesium oxide, wherein the magnesium oxidecomprises grain particles, and wherein the grain particles areconfigured to occupy porous spaces within the magnesium oxide.
 3335. Themethod of claim 3320, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, wherein theinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3336. The method of claim3320, wherein the insulated conductor comprises a conductor disposed inan electrically insulating material, wherein the insulating material isdisposed in a sheath, and wherein the sheath comprises stainless steel.3337. The method of claim 3320, further comprising supporting theinsulated conductor on a support member and flowing a fluid into theopen wellbore through an orifice in the support member.
 3338. The methodof claim 3320, further comprising supporting the insulated conductor ona support member and flowing a substantially constant amount of fluidinto the open wellbore through critical flow orifices in the supportmember.
 3339. The method of claim 3320, wherein a perforated tube isdisposed in the open wellbore proximate to the insulated conductor, themethod further comprising flowing a fluid into the open wellbore throughthe perforated tube.
 3340. The method of claim 3320, wherein a tube isdisposed in the open wellbore proximate to the insulated conductor, themethod further comprising flowing a substantially constant amount afluid into the open wellbore through critical flow orifices in the tube.3341. The method of claim 3320, further comprising supporting theinsulated conductor on a support member and flowing a corrosioninhibiting fluid into the open wellbore through an orifice in thesupport member.
 3342. The method of claim 3320, wherein a perforatedtube is disposed in the open wellbore proximate to the insulatedconductor, the method further comprising flowing a corrosion inhibitingfluid into the open wellbore through the perforated tube.
 3343. Themethod of claim 3320, further comprising determining a temperaturedistribution in the insulated conductor using an electromagnetic signalprovided to the insulated conductor.
 3344. The method of claim 3320,further comprising monitoring a leakage current of the insulatedconductor.
 3345. The method of claim 3320, further comprising monitoringthe applied electrical current.
 3346. The method of claim 3320, furthercomprising monitoring a voltage applied to the insulated conductor.3347. The method of claim 3320, further comprising monitoring atemperature in the insulated conductor with at least one thermocouple.3348. The method of claim 3320, further comprising electrically couplinga lead-in conductor to the insulated conductor, wherein the lead-inconductor comprises a low resistance conductor configured to generatesubstantially no heat.
 3349. The method of claim 3320, furthercomprising electrically coupling a lead-in conductor to the insulatedconductor using a cold pin transition conductor.
 3350. The method ofclaim 3320, further comprising electrically coupling a lead-in conductorto the insulated conductor using a cold pin transition conductor,wherein the cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 3351. The method of claim 3320, furthercomprising coupling an overburden casing to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation.3352. The method of claim
 3320. further comprising coupling anoverburden casing to the open wellbore, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing comprises steel.
 3353. The method of claim 3320, furthercomprising coupling an overburden casing to the open wellbore, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3354. Themethod of claim 3320, further comprising coupling an overburden casingto the open wellbore, wherein the overburden casing is disposed in anoverburden of the formation, and wherein a packing material is disposedat a junction of the overburden casing and the open wellbore.
 3355. Themethod of claim 3320, further comprising coupling an overburden casingto the open wellbore, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the method further comprisesinhibiting a flow of fluid between the open wellbore and the overburdencasing with a packing material.
 3356. The method of claim 3320, furthercomprising heating at least the portion of the formation to pyrolyze atleast some hydrocarbons within the formation.
 3357. An in situ methodfor heating a hydrocarbon containing formation, comprising: applying anelectrical current to an insulated conductor to provide heat to at leasta portion of the formation, wherein the insulated conductor is disposedwithin an opening in the formation; and allowing the heat to transferfrom the insulated conductor to a section of the formation.
 3358. Themethod of claim 1, further comprising supporting the insulated conductoron a support member.
 3359. The method of claim 1, further comprisingsupporting the insulated conductor on a support member and maintaining alocation of the first insulated conductor on the support member with acentralizer.
 3360. The method of claim 1, wherein the insulatedconductor is coupled to two additional insulated conductors, wherein theinsulated conductor and the two insulated conductors are disposed withinthe opening, and wherein the three insulated conductors are electricallycoupled in a 3-phase Y configuration.
 3361. The method of claim 1,wherein an additional insulated conductor is disposed within theopening.
 3362. The method of claim 1, wherein an additional insulatedconductor is disposed within the opening, and wherein the insulatedconductor and the additional insulated conductor are electricallycoupled in a series configuration.
 3363. The method of claim 1, whereinan additional insulated conductor is disposed within the opening, andwherein the insulated conductor and the additional insulated conductorare electrically coupled in a parallel configuration.
 3364. The methodof claim 1, wherein the provided heat comprises approximately 500 W/m toapproximately 150 W/m.
 3365. The method of claim 1, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, and wherein the conductor comprises a copper-nickelalloy.
 3366. The method of claim 1, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,wherein the conductor comprises a copper-nickel alloy, and wherein thecopper-nickel alloy comprises approximately 7% nickel by weight toapproximately 12% nickel by weight.
 3367. The method of claim 1, whereinthe insulated conductor comprises a conductor disposed in anelectrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 2% nickel by weight to approximately 6% nickel by weight.3368. The method of claim 1, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises magnesium oxide. 3369.The method of claim 1, wherein the insulated conductor comprises aconductor disposed in an electrically insulating material, wherein theelectrically insulating material comprises magnesium oxide, and whereinthe magnesium oxide comprises a thickness of at least approximately 1mm.
 3370. The method of claim 1, wherein the insulated conductorcomprises a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises aluminumoxide and magnesium oxide.
 3371. The method of claim 1, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, wherein the magnesium oxide comprises grainparticles, and wherein the grain particles are configured to occupyporous spaces within the magnesium oxide.
 3372. The method of claim 1,wherein the insulated conductor comprises a conductor disposed in anelectrically insulating material, wherein the insulating material isdisposed in a sheath, and wherein the sheath comprises acorrosion-resistant material.
 3373. The method of claim 1, wherein theinsulated conductor comprises a conductor disposed in an electricallyinsulating material, wherein the insulating material is disposed in asheath, and wherein the sheath comprises stainless steel.
 3374. Themethod of claim 1, further comprising supporting the insulated conductoron a support member and flowing a fluid into the opening through anorifice in the support member.
 3375. The method of claim 1, furthercomprising supporting the insulated conductor on a support member andflowing a substantially constant amount of fluid into the openingthrough critical flow orifices in the support member.
 3376. The methodof claim 1, wherein a perforated tube is disposed in the openingproximate to the insulated conductor, the method further comprisingflowing a fluid into the opening through the perforated tube.
 3377. Themethod of claim 1, wherein a tube is disposed in the opening proximateto the insulated conductor, the method further comprising flowing asubstantially constant amount a fluid into the opening through criticalflow orifices in the tube.
 3378. The method of claim 1, furthercomprising supporting the insulated conductor on a support member andflowing a corrosion inhibiting fluid into the opening through an orificein the support member.
 3379. The method of claim 1, wherein a perforatedtube is disposed in the opening proximate to the insulated conductor,the method further comprising flowing a corrosion inhibiting fluid intothe opening through the perforated tube.
 3380. The method of claim 1,further comprising determining a temperature distribution in theinsulated conductor using an electromagnetic signal provided to theinsulated conductor.
 3381. The method of claim 1, further comprisingmonitoring a leakage current of the insulated conductor.
 3382. Themethod of claim 1, further comprising monitoring the applied electricalcurrent.
 3383. The method of claim 1, further comprising monitoring avoltage applied to the insulated conductor.
 3384. The method of claim 1,further comprising monitoring a temperature in the insulated conductorwith at least one thermocouple.
 3385. The method of claim 1, furthercomprising electrically coupling a lead-in conductor to the insulatedconductor, wherein the lead-in conductor comprises a low resistanceconductor configured to generate substantially no heat.
 3386. The methodof claim 1 further comprising electrically coupling a lead-in conductorto the insulated conductor using a cold pin transition conductor. 3387.The method of claim 1, further comprising electrically coupling alead-in conductor to the insulated conductor using a cold pin transitionconductor, wherein the cold pin transition conductor comprises asubstantially low resistance insulated conductor.
 3388. The method ofclaim 1, further comprising coupling an overburden casing to theopening, wherein the overburden casing is disposed in an overburden ofthe formation.
 3389. The method of claim 1, further comprising couplingan overburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing comprises steel.
 3390. The method of claim 1, further comprisingcoupling an overburden casing to the opening, wherein the overburdencasing is disposed in an overburden of the formation, and wherein theoverburden casing is further disposed in cement.
 3391. The method ofclaim 1, further comprising coupling an overburden casing to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein a packing material is disposed at a junctionof the overburden casing and the opening.
 3392. The method of claim 1further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3393. Themethod of claim 1, further comprising heating at least the portion ofthe formation to substantially pyrolyze at least some hydrocarbonswithin the formation.
 3394. A system configured to heat a hydrocarboncontaining formation, comprising: an insulated conductor disposed withinan opening in the formation, wherein the insulated conductor isconfigured to provide heat to at least a portion of the formation duringuse, wherein the insulated conductor comprises a copper-nickel alloy,and wherein the copper-nickel alloy comprises approximately 7% nickel byweight to approximately 12% nickel by weight; and wherein the system isconfigured to allow heat to transfer from the insulated conductor to aselected section of the formation during use.
 3395. The system of claim3394, wherein the insulated conductor is further configured to generateheat during application of an electrical current to the insulatedconductor during use.
 3396. The system of claim 3394, further comprisinga support member, wherein the support member is configured to supportthe insulated conductor.
 3397. The system of claim 3394, furthercomprising a support member and a centralizer, wherein the supportmember is configured to support the insulated conductor, and wherein thecentralizer is configured to maintain a location of the insulatedconductor on the support member.
 3398. The system of claim 3394, whereinthe opening comprises a diameter of at least approximately 5 cm. 3399.The system of claim 3394, further comprising a lead-in conductor coupledto the insulated conductor, wherein the lead-in conductor comprises alow resistance conductor configured to generate substantially no heat.3400. The system of claim 3394, further comprising a lead-in conductorcoupled to the insulated conductor, wherein the lead-in conductorcomprises a rubber insulated conductor.
 3401. The system of claim 3394,further comprising a lead-in conductor coupled to the insulatedconductor, wherein the lead-in conductor comprises a copper wire. 3402.The system of claim 3394, further comprising a lead-in conductor coupledto the insulated conductor with a cold pin transition conductor. 3403.The system of claim 3394, further comprising a lead-in conductor coupledto the insulated conductor with a cold pin transition conductor, whereinthe cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 3404. The system of claim 3394, whereinthe copper-nickel alloy is disposed in an electrically insulatingmaterial, and wherein the electrically insulating material comprises athermally conductive material.
 3405. The system of claim 3394, whereinthe copper-nickel alloy is disposed in an electrically insulatingmaterial, and wherein the electrically insulating material comprisesmagnesium oxide.
 3406. The system of claim 3394, wherein thecopper-nickel alloy is disposed in an electrically insulating materialwherein the electrically insulating material comprises magnesium oxide,and wherein the magnesium oxide comprises a thickness of at leastapproximately 1 mm.
 3407. The system of claim 3394, wherein thecopper-nickel alloy is disposed in an electrically insulating material,and wherein the electrically insulating material comprises aluminumoxide and magnesium oxide.
 3408. The system of claim 3394, wherein thecopper-nickel alloy is disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,wherein the magnesium oxide comprises grain particles, and wherein thegrain particles are configured to occupy porous spaces within themagnesium oxide.
 3409. The system of claim 3394, wherein thecopper-nickel alloy is disposed in an electrically insulating material,wherein the electrically insulating material is disposed in a sheath,and wherein the sheath comprises a corrosion-resistant material. 3410.The system of claim 3394, wherein the copper-nickel alloy is disposed inan electrically insulating material, wherein the electrically insulatingmaterial is disposed in a sheath and wherein the sheath comprisesstainless steel.
 3411. The system of claim 3394, further comprising twoadditional insulated conductors, wherein the insulated conductor and thetwo additional insulated conductors are configured in a 3-phase Yconfiguration.
 3412. The system of claim 3394, further comprising anadditional insulated conductor, wherein the insulated conductor and theadditional insulated conductor are coupled to a support member, andwherein the insulated conductor and the additional insulated conductorare configured in a series electrical configuration.
 3413. The system ofclaim 3394, further comprising an additional insulated conductor,wherein the insulated conductor and the additional insulated conductorare coupled to a support member, and wherein the insulated conductor andthe additional insulated conductor are configured in a parallelelectrical configuration.
 3414. The system of claim 3394, wherein theinsulated conductor is configured to generate radiant heat ofapproximately 500 W/m to approximately 1150 W/m during use.
 3415. Thesystem of claim 3394, further comprising a support member configured tosupport the insulated conductor, wherein the support member comprisesorifices configured to provide fluid flow through the support memberinto the opening during use.
 3416. The system of claim 3394, furthercomprising a support member configured to support the insulatedconductor, wherein the support member comprises critical flow orificesconfigured to provide a substantially constant amount of fluid flowthrough the support member into the opening during use.
 3417. The systemof claim 3394, further comprising a tube coupled to the insulatedconductor, wherein the tube is configured to provide a flow of fluidinto the opening during use.
 3418. The system of claim 3394, furthercomprising a tube coupled to the insulated conductor, wherein the tubecomprises critical flow orifices configured to provide a substantiallyconstant amount of fluid flow through the support member into theopening during use.
 3419. The system of claim 3394, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 3420. The systemof claim 3394, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 3421.The system of claim 3394, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3422. The system of claim 3394, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3423. The system of claim 3394, furthercomprising an overburden casing, coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing, material is configured tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3424. The system of claim 3394, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3425. The system of claim 3394, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, the system further comprising a wellheadcoupled to the overburden casing and a lead-in conductor coupled to theinsulated conductor wherein the wellhead is disposed external to theoverburden wherein the wellhead comprises at least one sealing flange,and wherein at least the one sealing flange is configured to couple tothe lead-in conductor.
 3426. The system of claim 3394, wherein thesystem is further configured to transfer heat such that the transferredheat can pyrolyze at least some hydrocarbons in the selected section.3427. A system configurable to heat a hydrocarbon containing formation,comprising: an insulated conductor configurable to be disposed within anopening in the formation, wherein the insulated conductor is furtherconfigurable to provide heat to at least a portion of the formationduring use, wherein the insulated conductor comprises a copper-nickelalloy, and wherein the copper-nickel alloy comprises approximately 7%nickel by weight to approximately 12% nickel by weight; wherein thesystem is configurable to allow heat to transfer from the insulatedconductor to a selected section of the formation during use.
 3428. Thesystem of claim 3427, wherein the insulated conductor is furtherconfigurable to generate heat during application of an electricalcurrent to the insulated conductor during use.
 3429. The system of claim3427, further comprising a support member, wherein the support member isconfigurable to support the insulated conductor.
 3430. The system ofclaim 3427, further comprising a support member and a centralizer,wherein the support member is configurable to support the insulatedconductor, and wherein the centralizer is configurable to maintain alocation of the insulated conductor on the support member.
 3431. Thesystem of claim 3427, wherein the opening comprises a diameter of atleast approximately 5 cm.
 3432. The system of claim 3427, furthercomprising a lead-in conductor coupled to the insulated conductor,wherein the lead-in conductor comprises a low resistance conductorconfigurable to generate substantially no heat.
 3433. The system ofclaim 3427, further comprising a lead-in conductor coupled to theinsulated conductor, wherein the lead-in conductor comprises a rubberinsulated conductor.
 3434. The system of claim 3427, further comprisinga lead-in conductor coupled to the insulated conductor, wherein thelead-in conductor comprises a copper wire.
 3435. The system of claim3427, further comprising a lead-in conductor coupled to the insulatedconductor with a cold pin transition conductor.
 3436. The system ofclaim 3427, further comprising a lead-in conductor coupled to theinsulated conductor with a cold pin transition conductor, wherein thecold pin transition conductor comprises a substantially low resistanceinsulated conductor.
 3437. The system of claim 3427, wherein thecopper-nickel alloy is disposed in an electrically insulating material,and wherein the electrically insulating material comprises a thermallyconductive material.
 3438. The system of claim 3427, wherein thecopper-nickel alloy is disposed in an electrically insulating material,and wherein the electrically insulating material comprises magnesiumoxide.
 3439. The system of claim 3427, wherein the copper-nickel alloyis disposed in an electrically insulating material, wherein theelectrically insulating material comprises magnesium oxide, and whereinthe magnesium oxide comprises a thickness of at least approximately 1mm.
 3440. The system of claim 3427, wherein the copper-nickel alloy isdisposed in an electrically insulating material, and wherein theelectrically insulating material comprises aluminum oxide and magnesiumoxide.
 3441. The system of claim 3427, wherein the copper-nickel alloyis disposed in an electrically insulating material, wherein theelectrically insulating material comprises magnesium oxide, wherein themagnesium oxide comprises grain particles, and wherein the grainparticles are configurable to occupy porous spaces within the magnesiumoxide.
 3442. The system of claim 3427, wherein the copper-nickel alloyis disposed in an electrically insulating material, wherein theelectrically insulating material is disposed in a sheath, and whereinthe sheath comprises a corrosion-resistant material.
 3443. The system ofclaim 3427, wherein the copper-nickel alloy is disposed in anelectrically insulating material, wherein the electrically insulatingmaterial is disposed in a sheath, and wherein the sheath comprises stainless steel.
 3444. The system of claim 3427, further comprising twoadditional insulated conductors, wherein the insulated conductor and thetwo additional insulated conductors are configurable in a 3-phase Yconfiguration.
 3445. The system of claim 3427, further comprising anadditional insulated conductor, wherein the insulated conductor and theadditional insulated conductor are coupled to a support member, andwherein the insulated conductor and the additional insulated conductorare configurable in a series electrical configuration.
 3446. The systemof claim 3427, further comprising an additional insulated conductorwherein the insulated conductor and the additional insulated conductorare coupled to a support member, and wherein the insulated conductor andthe additional insulated conductor are configurable in a parallelelectrical configuration.
 3447. The system of claim 3427, wherein theinsulated conductor is configurable to generate radiant heat ofapproximately 500 W/m to approximately 1150 W/m during use.
 3448. Thesystem of claim 3427, further comprising a support member configurableto support the insulated conductor, wherein the support member comprisesorifices configurable to provide fluid flow through the support memberinto the open wellbore during use.
 3449. The system of claim 3427,further comprising a support member configurable to support theinsulated conductor, wherein the support member comprises critical floworifices configurable to provide a substantially constant amount offluid flow through the support member into the opening during use. 3450.The system of claim 3427, further comprising a tube coupled to theinsulated conductor, wherein the tube is configurable to provide a flowof fluid into the opening during use.
 3451. The system of claim 3427,further comprising a tube coupled to the insulated conductor, whereinthe tube comprises critical flow orifices configurable to provide asubstantially constant amount of fluid flow through the support memberinto the opening during use.
 3452. The system of claim 3427, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3453.The system of claim 3427 further comprising an overburden casing coupledto the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3454. The system of claim 3427, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3455. The system of claim 3427, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3456. The system of claim 3427, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing, material is configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3457. The system of claim 3427, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3458. The system of claim 3427, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, the system further comprising a wellheadcoupled to the overburden casing and a lead-in conductor coupled to theinsulated conductor, wherein the wellhead is disposed external to theoverburden, wherein the wellhead comprises at least one sealing flange,and wherein at least the one sealing flange is configurable to couple tothe lead-in conductor.
 3459. The system of claim 3427, wherein thesystem is further configured to transfer heat such that the transferredheat can pyrolyze at least some hydrocarbons in the selected section.3460. An in situ method for heating a hydrocarbon containing formation,comprising: applying an electrical current to an insulated conductor toprovide heat to at least a portion of the formation, wherein theinsulated conductor is disposed within an opening in the formation, andwherein the insulated conductor comprises a copper-nickel allow ofapproximately 7% nickel by weight to approximately 12% nickel by weight;and allowing the heat to transfer from the insulated conductor to aselected section of the formation.
 3461. The method of claim 3460,further comprising supporting the insulated conductor on a supportmember.
 3462. The method of claim 3460, further comprising supportingthe insulated conductor on a support member and maintaining a locationof the first insulated conductor on the support member with acentralizer.
 3463. The method of claim 3460, wherein the insulatedconductor is coupled to two additional insulated conductors, wherein theinsulated conductor and the two insulated conductors are disposed withinthe opening, and wherein the three insulated conductors are electricallycoupled in a 3-phase Y configuration.
 3464. The method of claim 3460,wherein an additional insulated conductor is disposed within theopening.
 3465. The method of claim 3460, wherein an additional insulatedconductor is disposed within the opening, and wherein the insulatedconductor and the additional insulated conductor are electricallycoupled in a series configuration.
 3466. The method of claim 3460,wherein an additional insulated conductor is disposed within theopening, and wherein the insulated conductor and the additionalinsulated conductor are electrically coupled in a parallelconfiguration.
 3467. The method of claim 3460, wherein the provided heatcomprises approximately 500 W/m to approximately 1150 W/m.
 3468. Themethod of claim 3460, wherein the copper-nickel alloy is disposed in anelectrically insulating material.
 3469. The method of claim 3460,wherein the copper-nickel alloy is disposed in an electricallyinsulating material, and wherein the electrically insulating materialcomprises magnesium oxide.
 3470. The method of claim 3460, wherein thecopper-nickel alloy is disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,and wherein the magnesium oxide comprises a thickness of at leastapproximately 1 mm.
 3471. The method of claim 3460, wherein thecopper-nickel alloy is disposed in an electrically insulating material,and wherein the electrically insulating material comprises aluminumoxide and magnesium oxide.
 3472. The method of claim 3460, wherein thecopper-nickel alloy is disposed in an electrically insulating material,wherein the electrically insulating material comprises magnesium oxide,wherein the magnesium oxide comprises grain particles, and wherein thegrain particles are configured to occupy porous spaces within themagnesium oxide.
 3473. The method of claim 3460, wherein thecopper-nickel alloy is disposed in an electrically insulating material,wherein the insulating material is disposed in a sheath, and wherein thesheath comprises a corrosion-resistant material.
 3474. The method ofclaim 3460, wherein the copper-nickel alloy is disposed in anelectrically insulating material, wherein the insulating material isdisposed in a sheath, and wherein the sheath comprises stainless steel.3475. The method of claim 3460, further comprising supporting theinsulated conductor on a support member and flowing a fluid into theopening through an orifice in the support member.
 3476. The method ofclaim 3460, further comprising supporting the insulated conductor on asupport member and flowing a substantially constant amount of fluid intothe opening through critical flow orifices in the support member. 3477.The method of claim 3460, wherein a perforated tube is disposed in theopening proximate to the insulated conductor, the method furthercomprising flowing a fluid into the opening through the perforated tube.3478. The method of claim 3460, wherein a tube is disposed in theopening proximate to the insulated conductor the method furthercomprising flowing a substantially constant amount a fluid into theopening through critical flow orifices in the tube.
 3479. The method ofclaim 3460, further comprising supporting the insulated conductor on asupport member and flowing a corrosion inhibiting fluid into the openingthrough an orifice in the support member.
 3480. The method of claim3460, wherein a perforated tube is disposed in the opening proximate tothe insulated conductor, the method further comprising flowing acorrosion inhibiting fluid into the opening through the perforated tube.3481. The method of claim 3460, further comprising determining atemperature distribution in the insulated conductor using anelectromagnetic signal provided to the insulated conductor.
 3482. Themethod of claim 3460, further comprising monitoring a leakage current ofthe insulated conductor.
 3483. The method of claim 3460, furthercomprising monitoring the applied electrical current.
 3484. The methodof claim 3460, further comprising monitoring a voltage applied to theinsulated conductor.
 3485. The method of claim 3460, further comprisingmonitoring a temperature in the insulated conductor with at least onethermocouple.
 3486. The method of claim 3460, further comprisingelectrically coupling a lead-in conductor to the insulated conductor,wherein the lead-in conductor comprises a low resistance conductorconfigured to generate substantially no heat.
 3487. The method of claim3460, further comprising electrically coupling a lead-in conductor tothe insulated conductor using a cold pin transition conductor.
 3488. Themethod of claim 3460, further comprising electrically coupling a lead-inconductor to the insulated conductor using a cold pin transitionconductor, wherein the cold pin transition conductor comprises asubstantially low resistance insulated conductor.
 3489. The method ofclaim 3460, further comprising coupling an overburden casing to theopening, wherein the overburden casing is disposed in an overburden ofthe formation.
 3490. The method of claim 3460, further comprisingcoupling an overburden casing to the opening, wherein the overburdencasing is disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3491. The method of claim 3460,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3492. Themethod of claim 3460, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein a packing material is disposedat a junction of the overburden casing and the opening.
 3493. The methodof claim 3460, further comprising coupling an overburden casing to theopening wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the method further comprises inhibiting aflow of fluid between the opening and the overburden casing with apacking material.
 3494. The method of claim 3460, further comprisingheating at least the portion of the formation to substantially pyrolyzeat least some hydrocarbons within the formation.
 3495. A systemconfigured to heat a hydrocarbon containing formation, comprising: atleast three insulated conductors disposed within an opening in theformation, wherein at least the three insulated conductors areelectrically coupled in a 3-phase Y configuration, and wherein at leastthe three insulated conductors are configured to provide heat to atleast a portion of the formation during use; and wherein the system isconfigured to allow heat to transfer from at least the three insulatedconductors to a selected section of the formation during use.
 3496. Thesystem of claim 3495, wherein at least the three insulated conductorsare further configured to generate heat during application of anelectrical current to at least the three insulated conductors duringuse.
 3497. The system of claim 3495, further comprising a supportmember, wherein the support member is configured to support at least thethree insulated conductors.
 3498. The system of claim 3495, furthercomprising a support member and a centralizer, wherein the supportmember is configured to support at least the three insulated conductors,and wherein the centralizer is configured to maintain a location of atleast the three insulated conductors on the support member.
 3499. Thesystem of claim 3495, wherein the opening comprises a diameter of atleast approximately 5 cm.
 3500. The system of claim
 3495. furthercomprising at least one lead-in conductor coupled to at least the threeinsulated conductors wherein at least the one lead-in conductorcomprises a low resistance conductor configured to generatesubstantially no heat.
 3501. The system of claim 3495, furthercomprising at least one lead-in conductor coupled to at least the threeinsulated conductors, wherein at least the one lead-in conductorcomprises a rubber insulated conductor.
 3502. The system of claim 3495,further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors, wherein at least the one lead-inconductor comprises a copper wire.
 3503. The system of claim 3495,further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors with a cold pin transition conductor.3504. The system of claim 3495, further comprising at least one lead-inconductor coupled to at least the three insulated conductors with a coldpin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3505. Thesystem of claim 3495, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the electrically insulating material is disposed in asheath.
 3506. The system of claim 3495, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, and wherein the conductor comprises a copper-nickelalloy.
 3507. The system of claim 3495, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the conductor comprises a copper-nickelalloy, and wherein the copper-nickel alloy comprises approximately 7%nickel by weight to approximately 12% nickel by weight.
 3508. The systemof claim 3495, wherein at least the three insulated conductors comprisea conductor disposed in an electrically insulating material, wherein theconductor comprises a copper-nickel alloy, and wherein the copper-nickelalloy comprises approximately 2% nickel by weight to approximately 6%nickel by weight.
 3509. The system of claim 3495, wherein at least thethree insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises a thermally conductive material.
 3510. Thesystem of claim 3495, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises magnesiumoxide.
 3511. The system of claim 3495, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, and wherein the magnesium oxide comprises athickness of at least approximately 1 mm.
 3512. The system of claim3495, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises aluminum oxide andmagnesium oxide.
 3513. The system of claim 3495, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, wherein the electrically insulating material comprisesmagnesium oxide, wherein the magnesium oxide comprises grain particles,and wherein the grain particles are configured to occupy porous spaceswithin the magnesium oxide.
 3514. The system of claim 3495, wherein atleast the three insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3515. The system of claim 3495wherein at least the three insulated conductors comprise a conductordisposed in an electrically insulating material, and wherein theelectrically insulating material is disposed in a sheath, and whereinthe sheath comprises stainless steel.
 3516. The system of claim 3495,wherein at least the three insulated conductors are configured togenerate radiant heat of approximately 500 W/m to approximately 1150 W/mof at least the three insulated conductors during use.
 3517. The systemof claim 3495, further comprising a support member configured to supportat least the three insulated conductors, wherein the support membercomprises orifices configured to provide fluid flow through the supportmember into the opening during use.
 3518. The system of claim 3495,further comprising a support member configured to support at least thethree insulated conductors, wherein the support member comprisescritical flow orifices configured to provide a substantially constantamount of fluid flow through the support member into the opening duringuse.
 3519. The system of claim 3495, further comprising a tube coupledto at least the three insulated conductors wherein the tube isconfigured to provide a flow of fluid into the opening during use. 3520.The system of claim 3495, further comprising a tube coupled to at leastthe three insulated conductors, wherein the tube comprises critical floworifices configured to provide a substantially constant amount of fluidflow through the support member into the opening during use.
 3521. Thesystem of claim 3495, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3522. The system of claim 3495, further comprising anoverburden casing coupled to the opening wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3523. The system of claim 3495,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3524. Thesystem of claim 3495, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3525. The system ofclaim 3495, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configured to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3526. The system of claim3495, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3527. The system of claim 3495, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigured to couple to the lead-in conductor.
 3528. The system of claim3495, wherein the system is further configured to transfer heat suchthat the transferred heat can pyrolyze at least some hydrocarbons in theselected section.
 3529. A system configurable to heat a hydrocarboncontaining formation, comprising: at least three insulated conductorsconfigurable to be disposed within an opening in the formation, whereinat least the three insulated conductors are electrically coupled in a3-phase Y configuration, and wherein at least the three insulatedconductors are further configurable to provide heat to at least aportion of the formation during use; and wherein the system isconfigurable to allow heat to transfer from at least the three insulatedconductors to a selected section of the formation during use.
 3530. Thesystem of claim 3529, wherein at least the three insulated conductorsare further configurable to generate heat during application of anelectrical current to at least the three insulated conductors duringuse.
 3531. The system of claim 3529, further comprising a supportmember, wherein the support member is configurable to support at leastthe three insulated conductors.
 3532. The system of claim 3529, furthercomprising a support member and a centralizer, wherein the supportmember is configurable to support at least the three insulatedconductors, and wherein the centralizer is configurable to maintain alocation of at least the three insulated conductors on the supportmember.
 3533. The system of claim 3529, wherein the opening comprises adiameter of at least approximately 5 cm.
 3534. The system of claim 3529further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors, wherein at least the one lead-inconductor comprises a low resistance conductor configurable to generatesubstantially no heat.
 3535. The system of claim 3529, furthercomprising at least one lead-in conductor coupled to at least the threeinsulated conductors, wherein at least the one lead-in conductorcomprises a rubber insulated conductor.
 3536. The system of claim 3529,further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors, wherein at least the one lead-inconductor comprises a copper wire.
 3537. The system of claim 3529,further comprising at least one lead-in conductor coupled to at leastthe three insulated conductors with a cold pin transition conductor.3538. The system of claim 3529, further comprising at least one lead-inconductor coupled to at least the three insulated conductors with a coldpin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3539. Thesystem of claim 3529, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the electrically insulating material is disposed in asheath.
 3540. The system of claim 3529, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, and wherein the conductor comprises a copper-nickelalloy.
 3541. The system of claim 3529, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the conductor comprises a copper-nickelalloy, and wherein the copper-nickel alloy comprises approximately 7%nickel by weight to approximately 12% nickel by weight.
 3542. The systemof claim 3529, wherein at least the three insulated conductors comprisea conductor disposed in an electrically insulating material, wherein theconductor comprises a copper-nickel alloy, and wherein the copper-nickelalloy comprises approximately 2% nickel by weight to approximately 6%nickel by weight.
 3543. The system of claim 3529, wherein at least thethree insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material comprises a thermally conductive material.
 3544. Thesystem of claim 3529, wherein at least the three insulated conductorscomprise a conductor disposed in an electrically insulating material,and wherein the electrically insulating material comprises magnesiumoxide.
 3545. The system of claim 3529, wherein at least the threeinsulated conductors comprise a conductor disposed in an electricallyinsulating material, wherein the electrically insulating materialcomprises magnesium oxide, and wherein the magnesium oxide comprises athickness of at least approximately 1 mm.
 3546. The system of claim3529, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises aluminum oxide andmagnesium oxide.
 3547. The system of claim 3529, wherein the insulatedconductor comprises a conductor disposed in an electrically insulatingmaterial, wherein the electrically insulating material comprisesmagnesium oxide, wherein the magnesium oxide comprises grain particles,and wherein the grain particles are configurable to occupy porous spaceswithin the magnesium oxide.
 3548. The system of claim 3529, wherein atleast the three insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the electricallyinsulating material is disposed in a sheath, and wherein the sheathcomprises a corrosion-resistant material.
 3549. The system of claim3529, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material is disposed in a sheath, andwherein the sheath comprises stainless steel.
 3550. The system of claim3529, wherein at least the three insulated conductors are configurableto generate radiant heat of approximately 500 W/m to approximately 1150W/m during use.
 3551. The system of claim 3529, further comprising asupport member configurable to support at least the three insulatedconductors, wherein the support member comprises orifices configurableto provide fluid flow through the support member into the opening duringuse.
 3552. The system of claim 3529, further comprising a support memberconfigurable to support at least the three insulated conductors, whereinthe support member comprises critical flow orifices configurable toprovide a substantially constant amount of fluid flow through thesupport member into the opening during use.
 3553. The system of claim3529, further comprising a tube coupled to at least the three insulatedconductors, wherein the tube is configurable to provide a flow of fluidinto the opening during use.
 3554. The system of claim 3529, furthercomprising a tube coupled to at least the three insulated conductors,wherein the tube comprises critical flow orifices configurable toprovide a substantially constant amount of fluid flow through thesupport member into the opening during use.
 3555. The system of claim3529, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation.
 3556. The system of claim 3529, further comprising anoverburden casing coupled to the opening wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3557. The system of claim 3529,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3558. Thesystem of claim 3529 further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3559. The system ofclaim 3529, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis configurable to substantially inhibit a flow of fluid between theopening and the overburden casing during use.
 3560. The system of claim3529, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation, wherein a packing material is disposed at a junction of theoverburden casing and the opening, and wherein the packing materialcomprises cement.
 3561. The system of claim 3529, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation the system furthercomprising a wellhead coupled to the overburden casing and a lead-inconductor coupled to the insulated conductor, wherein the wellhead isdisposed external to the overburden, wherein the wellhead comprises atleast one sealing flange, and wherein at least the one sealing flange isconfigurable to couple to the lead-in conductor.
 3562. The system ofclaim 3529 wherein the system is further configured to transfer heatsuch that the transferred heat can pyrolyze at least some hydrocarbonsin the selected section.
 3563. An in situ method for heating ahydrocarbon containing formation, comprising: applying an electricalcurrent to at least three insulated conductors to provide heat to atleast a portion of the formation, wherein at least the three insulatedconductors are disposed within an opening in the formation; and allowingthe heat to transfer from at least the three insulated conductors to aselected section of the formation.
 3564. The method of claim 3563,further comprising supporting at least the three insulated conductors ona support member.
 3565. The method of claim 3563, further comprisingsupporting at least the three insulated conductors on a support memberand maintaining a location of at least the three insulated conductors onthe support member with a centralizer.
 3566. The method of claim 3563,wherein the provided heat comprises approximately 500 W/m toapproximately 1150 W/m.
 3567. The method of claim 3563, where in atleast the three insulated conductors comprise a conductor disposed in anelectrically insulating material, and wherein the conductor comprises acopper-nickel alloy.
 3568. The method of claim 3563, wherein at leastthe three insulated conductors comprise a conductor disposed in anelectrically insulating material, wherein the conductor comprises acopper-nickel alloy, and wherein the copper-nickel alloy comprisesapproximately 7% nickel by weight to approximately 12% nickel by weight.3569. The method of claim 3563, wherein at least the three insulatedconductors comprise a conductor disposed in an electrically insulatingmaterial, wherein the conductor comprises a copper-nickel alloy, andwherein the copper-nickel alloy comprises approximately 2% nickel byweight to approximately 6% nickel by weight.
 3570. The method of claim3563, wherein at least the three insulated conductors comprise aconductor disposed in an electrically insulating material, and whereinthe electrically insulating material comprises magnesium oxide. 3571.The method of claim 3563, wherein at least the three insulatedconductors comprise a conductor disposed in an electrically insulatingmaterial, wherein the electrically insulating material comprisesmagnesium oxide, and wherein the magnesium oxide comprises a thicknessof at least approximately 1 mm.
 3572. The method of claim 3563, whereinat least the three insulated conductors comprise a conductor disposed inan electrically insulating material, and wherein the electricallyinsulating material comprises aluminum oxide and magnesium oxide. 3573.The method of claim 3563, wherein at least the three insulatedconductors comprise a conductor disposed in an electrically insulatingmaterial, wherein the electrically insulating material comprisesmagnesium oxide, wherein the magnesium oxide comprises grain particles,and wherein the grain particles are configured to occupy porous spaceswithin the magnesium oxide.
 3574. The method of claim 3563, wherein atleast the three insulated conductors comprise a conductor disposed in anelectrically insulating material, wherein the insulating material isdisposed in a sheath, and wherein the sheath comprises acorrosion-resistant material.
 3575. The method of claim 3563, wherein atleast the three insulated conductors comprise a conductor disposed in anelectrically insulating material, wherein the insulating material isdisposed in a sheath, and wherein the sheath comprises stainless steel.3576. The method of claim 3563, further comprising supporting at leastthe three insulated conductors on a support member and flowing a fluidinto the opening through an orifice in the support member.
 3577. Themethod of claim 3563, further comprising supporting at least the threeinsulated conductors on a support member and flowing a substantiallyconstant amount of fluid into the opening through critical flow orificesin the support member.
 3578. The method of claim 3563, wherein aperforated tube is disposed in the opening proximate to at least thethree insulated conductors, the method further comprising flowing afluid into the opening through the perforated tube.
 3579. The method ofclaim 3563, wherein a tube is disposed in the opening proximate to atleast the three insulated conductors, the method further comprisingflowing a substantially constant amount a fluid into the opening throughcritical flow orifices in the tube.
 3580. The method of claim 3563further comprising supporting at least the three insulated conductors ona support member and flowing a corrosion inhibiting fluid into theopening through an orifice in the support member.
 3581. The method ofclaim 3563, wherein a perforated tube is disposed in the openingproximate to at least the three insulated conductors, the method furthercomprising flowing a corrosion inhibiting fluid into the opening throughthe perforated tube.
 3582. The method of claim 3563, further comprisingdetermining a temperature distribution in at least the three insulatedconductors using an electromagnetic signal provided to the insulatedconductor.
 3583. The method of claim 3563, further comprising monitoringa leakage current of at least the three insulated conductors.
 3584. Themethod of claim 3563, further comprising monitoring the appliedelectrical current.
 3585. The method of claim 3563, further comprisingmonitoring a voltage applied to at least the three insulated conductors.3586. The method of claim 3563, further comprising monitoring atemperature in at least the three insulated conductors with at least onethermocouple.
 3587. The method of claim 3563, further comprisingelectrically coupling a lead-in conductor to at least the threeinsulated conductors, wherein the lead-in conductor comprises a lowresistance conductor configured to generate substantially no heat. 3588.The method of claim 3563, further comprising electrically coupling alead-in conductor to at least the three insulated conductors using acold pin transition conductor.
 3589. The method of claim 3563, furthercomprising electrically coupling a lead-in conductor to at least thethree insulated conductors using a cold pin transition conductor,wherein the cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 3590. The method of claim 3563, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3591.The method of claim 3563, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3592. The method of claim 3563, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3593. The method of claim 3563,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3594. The method of claim 3563, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3595. Themethod of claim 3563, further comprising heating at least the portion ofthe formation to substantially pyrolyze at least some of thehydrocarbons within the formation.
 3596. A system configured to heat ahydrocarbon containing formation, comprising: a first conductor disposedin a first conduit, wherein the first conduit is disposed within anopening in the formation, and wherein the first conductor is configuredto provide heat to at least a portion of the formation during use; andwherein the system is configured to allow heat to transfer from thefirst conductor to a section of the formation during use.
 3597. Thesystem of claim 3596, wherein the first conductor is further configuredto generate heat during application of an electrical current to thefirst conductor.
 3598. The system of claim 3596, wherein the firstconductor comprises a pipe.
 3599. The system of claim 3596, wherein thefirst conductor comprises stainless steel.
 3600. The system of claim3596, wherein the first conduit comprises stainless steel.
 3601. Thesystem of claim 3596, further comprising a centralizer configured tomaintain a location of the first conductor within the first conduit.3602. The system of claim 3596, further comprising a centralizerconfigured to maintain a location of the first conductor within thefirst conduit, wherein the centralizer comprises ceramic material. 3603.The system of claim 3596, further comprising a centralizer configured tomaintain a location of the first conductor within the first conduit,wherein the centralizer comprises ceramic material and stainless steel.3604. The system of claim 3596, wherein the opening comprises a diameterof at least approximately 5 cm.
 3605. The system of claim 3596, furthercomprising a lead-in conductor coupled to the first conductor, whereinthe lead-in conductor comprises a low resistance conductor configured togenerate substantially no heat.
 3606. The system of claim 3596, furthercomprising a lead-in conductor coupled to the first conductor, whereinthe lead-in conductor comprises copper.
 3607. The system of claim 3596,further comprising a sliding electrical connector coupled to the firstconductor.
 3608. The system of claim 3596, further comprising a slidingelectrical connector coupled to the first conductor, wherein the slidingelectrical connector is further coupled to the first conduit.
 3609. Thesystem of claim 3596, further comprising a sliding electrical connectorcoupled to the first conductor, wherein the sliding electrical connectoris further coupled to the first conduit, and wherein the slidingelectrical connector is configured to complete an electrical circuitwith the first conductor and the first conduit.
 3610. The system ofclaim 3596, further comprising a second conductor disposed within thefirst conduit and at least one sliding electrical connector coupled tothe first conductor and the second conductor, wherein at least the onesliding electrical connector is configured to generate less heat thanthe first conductor or the second conductor during use.
 3611. The systemof claim 3596, wherein the first conduit comprises a first section and asecond section, wherein a thickness of the first section is greater thana thickness of the second section such that heat radiated from the firstconductor to the section along the first section of the conduit is lessthan heat radiated from the first conductor to the section along thesecond section of the conduit.
 3612. The system of claim 3596, furthercomprising a fluid disposed within the first conduit, wherein the fluidis configured to maintain a pressure within the first conduit tosubstantially inhibit deformation of the first conduit during use. 3613.The system of claim 3596, further comprising a thermally conductivefluid disposed within the first conduit.
 3614. The system of claim 3596,further comprising a thermally conductive fluid disposed within thefirst conduit, wherein the thermally conductive fluid comprises helium.3615. The system of claim 3596, further comprising a fluid disposedwithin the first conduit, wherein the fluid is configured tosubstantially inhibit arcing between the first conductor and the firstconduit during use.
 3616. The system of claim 3596, further comprising atube disposed within the opening external to the first conduit, whereinthe tube is configured to remove vapor produced from at least the heatedportion of the formation such that a pressure balance is maintainedbetween the first conduit and the opening to substantially inhibitdeformation of the first conduit during use.
 3617. The system of claim3596, wherein the first conductor is further configured to generateradiant heat of approximately 650 W/m to approximately 1650 W/m duringuse.
 3618. The system of claim 3596, further comprising a secondconductor disposed within a second conduit and a third conductordisposed within a third conduit, wherein first conduit, the secondconduit and the third conduit are disposed in different openings of theformation, wherein the first conductor is electrically coupled to thesecond conductor and the third conductor, and wherein the first, second,and third conductors are configured to operate in a 3-phase Yconfiguration during use.
 3619. The system of claim 3596, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit.
 3620. The system of claim 3596, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit with a connector.
 3621. The system of claim3596, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation.
 3622. The system of claim 3596, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3623. The system of claim 3596,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3624. Thesystem of claim 3596, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3625. The system ofclaim 3596, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configured to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3626. The system ofclaim 3596, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor.
 3627. The system of claim3596, further comprising an overburden casing coupled to the opening anda substantially low resistance conductor disposed within the overburdencasing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3628. Thesystem of claim 3596, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configured to support thesubstantially low resistance conductor within the overburden casing.3629. The system of claim 3596, wherein the heated section of theformation is substantially pyrolyzed.
 3630. A system configurable toheat a hydrocarbon containing formation, comprising: a first conductorconfigurable to be disposed in a first conduit, wherein the firstconduit is configurable to be disposed within an opening in theformation, and wherein the first conductor is further configurable toprovide heat to at least a portion of the formation during use; andwherein the system is configurable to allow heat to transfer from thefirst conductor to a section of the formation during use.
 3631. Thesystem of claim 3630, wherein the first conductor is furtherconfigurable to generate heat during application of an electricalcurrent to the first conductor.
 3632. The system of claim 3630, whereinthe first conductor comprises a pipe.
 3633. The system of claim 3630,wherein the first conductor comprises stainless steel.
 3634. The systemof claim 3630, wherein the first conduit comprises stainless steel.3635. The system of claim 3630, further comprising a centralizerconfigurable to maintain a location of the first conductor within thefirst conduit.
 3636. The system of claim 3630, further comprising acentralizer configurable to maintain a location of the first conductorwithin the first conduit, wherein the centralizer comprises ceramicmaterial.
 3637. The system of claim 3630, further comprising acentralizer configurable to maintain a location of the first conductorwithin the first conduit, wherein the centralizer comprises ceramicmaterial and stainless steel.
 3638. The system of claim 3630, whereinthe opening comprises a diameter of at least approximately 5 cm. 3639.The system of claim 3630, further comprising a lead-in conductor coupledto the first conductor, wherein the lead-in conductor comprises a lowresistance conductor configurable to generate substantially no heat.3640. The system of claim 3630, further comprising a lead-in conductorcoupled to the first conductor, wherein the lead-in conductor comprisescopper.
 3641. The system of claim 3630, further comprising a slidingelectrical connector coupled to the first conductor.
 3642. The system ofclaim 3630, further comprising a sliding electrical connector coupled tothe first conductor, wherein the sliding electrical connector is furthercoupled to the first conduit.
 3643. The system of claim 3630, furthercomprising a sliding electrical connector coupled to the firstconductor, wherein the sliding electrical connector is further coupledto the first conduit, and wherein the sliding electrical connector isconfigurable to complete an electrical circuit with the first conductorand the first conduit.
 3644. The system of claim 3630, furthercomprising a second conductor disposed within the first conduit and atleast one sliding electrical connector coupled to the first conductorand the second conductor, wherein at least the one sliding electricalconnector is configurable to generate less heat than the first conductoror the second conductor during use.
 3645. The system of claim 3630,wherein the first conduit comprises a first section and a secondsection, wherein a thickness of the first section is greater than athickness of the second section such that heat radiated from the firstconductor to the section along the first section of the conduit is lessthan heat radiated from the first conductor to the section along thesecond section of the conduit.
 3646. The system of claim 3630, furthercomprising a fluid disposed within the first conduit, wherein the fluidis configurable to maintain a pressure within the first conduit tosubstantially inhibit deformation of the first conduit during use. 3647.The system of claim 3630, further comprising a thermally conductivefluid disposed within the first conduit.
 3648. The system of claim 3630,further comprising a thermally conductive fluid disposed within thefirst conduit, wherein the thermally conductive fluid comprises helium.3649. The system of claim 3630, further comprising a fluid disposedwithin the first conduit, wherein the fluid is configurable tosubstantially inhibit arcing between the first conductor and the firstconduit during use.
 3650. The system of claim 3630, further comprising atube disposed within the opening external to the first conduit, whereinthe tube is configurable to remove vapor produced from at least theheated portion of the formation such that a pressure balance ismaintained between the first conduit and the opening to substantiallyinhibit deformation of the first conduit during use.
 3651. The system ofclaim 3630, wherein the first conductor is further configurable togenerate radiant heat of approximately 650 W/m to approximately 1650 W/mduring use.
 3652. The system of claim 3630, further comprising a secondconductor disposed within a second conduit and a third conductordisposed within a third conduit, wherein first conduit, the secondconduit and the third conduit are disposed in different openings of theformation, wherein the first conductor is electrically coupled to thesecond conductor and the third conductor, and wherein the first, second,and third conductors are configurable to operate in a 3-phase Yconfiguration during use.
 3653. The system of claim 3630, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit.
 3654. The system of claim 3630, furthercomprising a second conductor disposed within the first conduit, whereinthe second conductor is electrically coupled to the first conductor toform an electrical circuit with a connector.
 3655. The system of claim3630, further comprising an overburden casing coupled to the opening,wherein the overburden casing is disposed in an overburden of theformation.
 3656. The system of claim 3630, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3657. The system of claim 3630,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3658. Thesystem of claim 3630 further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3659. The system ofclaim 3630, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configurable to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3660. The system ofclaim 3630, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor.
 3661. The system of claim3630, further comprising an overburden casing coupled to the opening,and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3662. Thesystem of claim 3630, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configurable to support thesubstantially low resistance conductor within the overburden casing.3663. The system of claim 3630, wherein the heated section of theformation is substantially pyrolyzed.
 3664. An in situ method forheating a hydrocarbon containing formation, comprising: applying anelectrical current to a first conductor to provide heat to at least aportion of the formation, wherein the first conductor is disposed in afirst conduit, and wherein the first conduit is disposed within anopening in the formation; and allowing the heat to transfer from thefirst conductor to a section of the formation.
 3665. The method of claim3664, wherein the first conductor comprises a pipe.
 3666. The method ofclaim 3664, wherein the first conductor comprises stainless steel. 3667.The method of claim 3664, wherein the first conduit comprises stainlesssteel.
 3668. The method of claim 3664, further comprising maintaining alocation of the first conductor in the first conduit with a centralizer.3669. The method of claim 3664, further comprising maintaining alocation of the first conductor in the first conduit with a centralizer,wherein the centralizer comprises ceramic material.
 3670. The method ofclaim 3664, further comprising maintaining a location of the firstconductor in the first conduit with a centralizer, wherein thecentralizer comprises ceramic material and stainless steel.
 3671. Themethod of claim 3664, further comprising coupling a sliding electricalconnector to the first conductor.
 3672. The method of claim 3664,further comprising electrically coupling a sliding electrical connectorto the first conductor and the first conduit, wherein the first conduitcomprises an electrical lead configured to complete an electricalcircuit with the first conductor.
 3673. The method of claim 3664,further comprising coupling a sliding electrical connector to the firstconductor and the first conduit, wherein the first conduit comprises anelectrical lead configured to complete an electrical circuit with thefirst conductor, and wherein the generated heat comprises approximately20 percent generated by the first conduit.
 3674. The method of claim3664, wherein the provided heat comprises approximately 650 W/m toapproximately 1650 W/m.
 3675. The method of claim 3664, furthercomprising determining a temperature distribution in the first conduitusing an electromagnetic signal provided to the conduit.
 3676. Themethod of claim 3664, further comprising monitoring the appliedelectrical current.
 3677. The method of claim 3664, further comprisingmonitoring a voltage applied to the first conductor.
 3678. The method ofclaim 3664, further comprising monitoring a temperature in the conduitwith at least one thermocouple.
 3679. The method of claim 3664, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation. 3680.The method of claim 3664, further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3681. The method of claim 3664, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing is further disposed in cement.
 3682. The method of claim 3664,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3683. The method of claim 3664, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the method further comprises inhibiting a flow of fluid betweenthe opening and the overburden casing with a packing material.
 3684. Themethod of claim 3664, further comprising coupling an overburden casingto the opening, wherein a substantially low resistance conductor isdisposed within the overburden casing, and wherein the substantially lowresistance conductor is electrically coupled to the first conductor.3685. The method of claim 3664, further comprising coupling anoverburden casing to the opening, wherein a substantially low resistanceconductor is disposed within the overburden casing, wherein thesubstantially low resistance conductor is electrically coupled to thefirst conductor, and wherein the substantially low resistance conductorcomprises carbon steel.
 3686. The method of claim 3664, furthercomprising coupling an overburden casing to the opening, wherein asubstantially low resistance conductor is disposed within the overburdencasing, wherein the substantially low resistance conductor iselectrically coupled to the first conductor, and wherein the methodfurther comprises maintaining a location of the substantially lowresistance conductor in the overburden casino with a centralizersupport.
 3687. The method of claim 3664, further comprising electricallycoupling a lead-in conductor to the first conductor, wherein the lead-inconductor comprises a low resistance conductor configured to generatesubstantially no heat.
 3688. The method of claim 3664, furthercomprising electrically coupling a lead-in conductor to the firstconductor wherein the lead-in conductor comprises copper.
 3689. Themethod of claim 3664, further comprising maintaining a sufficientpressure between the first conduit and the formation to substantiallyinhibit deformation of the first conduit.
 3690. The method of claim3664, further comprising providing a thermally conductive fluid withinthe first conduit.
 3691. The method of claim 3664, further comprisingproviding a thermally conductive fluid within the first conduit, whereinthe thermally conductive fluid comprises helium.
 3692. The method ofclaim 3664, further comprising inhibiting arcing between the firstconductor and the first conduit with a fluid disposed within the firstconduit.
 3693. The method of claim 3664, further comprising removing avapor from the opening using a perforated tube disposed proximate to thefirst conduit in the opening to control a pressure in the opening. 3694.The method of claim 3664, further comprising flowing a corrosioninhibiting fluid through a perforated tube disposed proximate to thefirst conduit in the opening.
 3695. The method of claim 3664, wherein asecond conductor is disposed within the first conduit, wherein thesecond conductor is electrically coupled to the first conductor to forman electrical circuit.
 3696. The method of claim 3664, wherein a secondconductor is disposed within the first conduit, wherein the secondconductor is electrically coupled to the first conductor with aconnector.
 3697. The method of claim 3664, wherein a second conductor isdisposed within a second conduit and a third conductor is disposedwithin a third conduit, wherein the second conduit and the third conduitare disposed in different openings of the formation, wherein the firstconductor is electrically coupled to the second conductor and the thirdconductor, and wherein the first, second, and third conductors areconfigured to operate in a 3-phase Y configuration.
 3698. The method ofclaim 3664, wherein a second conductor is disposed within the firstconduit, wherein at least one sliding electrical connector is coupled tothe first conductor and the second conductor, and wherein heat generatedby at least the one sliding electrical connector is less than heatgenerated by the first conductor or the second conductor.
 3699. Themethod of claim 3664, wherein the first conduit comprises a firstsection and a second section, wherein a thickness of the first sectionis greater than a thickness of the second section such that heatradiated from the first conductor to the section along the first sectionof the conduit is less than heat radiated from the first conductor tothe section along the second section of the conduit.
 3700. The method ofclaim 3664, further comprising flowing an oxidizing fluid through anorifice in the first conduit.
 3701. The method of claim 3664, furthercomprising disposing a perforated tube proximate to the first conduitand flowing an oxidizing fluid through the perforated tube.
 3702. Themethod of claim 3664, further comprising heating at least the portion ofthe formation to substantially pyrolyze at least some of the carbonwithin the formation.
 3703. A system configured to heat a hydrocarboncontaining formation, comprising: a first conductor disposed in a firstconduit, wherein the first conduit is disposed within a first opening inthe formation; a second conductor disposed in a second conduit, whereinthe second conduit is disposed within a second opening in the formation;a third conductor disposed in a third conduit, wherein the third conduitis disposed within a third opening in the formation, wherein the first,second, and third conductors are electrically coupled in a 3-phase Yconfiguration, and wherein the first, second, and third conductors areconfigured to provide heat to at least a portion of the formation duringuse; and wherein the system is configured to allow heat to transfer fromthe first, second, and third conductors to a selected section of theformation during use.
 3704. The system of claim 3703, wherein the first,second, and third conductors are further configured to generate heatduring application of an electrical current to the first conductor.3705. The system of claim 3703, wherein the first, second, and thirdconductors comprise a pipe.
 3706. The system of claim 3703, wherein thefirst, second, and third conductors comprise stainless steel.
 3707. Thesystem of claim 3703, wherein the first, second, and third openingscomprise a diameter of at least approximately 5 cm.
 3708. The system ofclaim 3703, further comprising a first sliding electrical connectorcoupled to the first conductor and a second sliding electrical connectorcoupled to the second conductor and a third sliding electrical connectorcoupled to the third conductor.
 3709. The system of claim 3703, furthercomprising a first sliding electrical connector coupled to the firstconductor, wherein the first sliding electrical connector is furthercoupled to the first conduit.
 3710. The system of claim 3703, furthercomprising a second sliding electrical connector coupled to the secondconductor, wherein the second sliding electrical connector is furthercoupled to the second conduit.
 3711. The system of claim 3703, furthercomprising a third sliding electrical connector coupled to the thirdconductor, wherein the third sliding electrical connector is furthercoupled to the third conduit.
 3712. The system of claim 3703, whereineach of the first, second, and third conduits comprises a first sectionand a second section, wherein a thickness of the first section isgreater than a thickness of the second section such that heat radiatedfrom each of the first, second, and third conductors to the sectionalong the first section of each of the conduits is less than heatradiated from the first, second, and third conductors to the sectionalong the second section of each of the conduits.
 3713. The system ofclaim 3703, further comprising a fluid disposed within the first,second, and third conduits, wherein the fluid is configured to maintaina pressure within the first conduit to substantially inhibit deformationof the first, second, and third conduits during use.
 3714. The system ofclaim 3703, further comprising a thermally conductive fluid disposedwithin the first, second, and third conduits.
 3715. The system of claim3703, further comprising a thermally conductive fluid disposed withinthe first, second, and third conduits, wherein the thermally conductivefluid comprises helium.
 3716. The system of claim 3703, furthercomprising a fluid disposed within the first, second, and thirdconduits, wherein the fluid is configured to substantially inhibitarcing between the first, second, and third conductors and the first,second, and third conduits during use.
 3717. The system of claim 3703,further comprising at least one tube disposed within the first, second,and third openings external to the first, second, and third conduits,wherein at least the one tube is configured to remove vapor producedfrom at least the heated portion of the formation such that a pressurebalance is maintained between the first, second, and third conduits andthe first, second, and third openings to substantially inhibitdeformation of the first, second, and third conduits during use. 3718.The system of claim 3703, wherein the first, second, and thirdconductors are further configured to generate radiant heat ofapproximately 650 W/m to approximately 1650 W/m during use.
 3719. Thesystem of claim 3703, further comprising at least one overburden casingcoupled to the first, second, and third openings, wherein at least theone overburden casing is disposed in an overburden of the formation.3720. The system of claim 3703, further comprising at least oneoverburden casing coupled to the first, second, and third openings,wherein at least the one overburden casing is disposed in an overburdenof the formation, and wherein at least the one overburden casingcomprises steel.
 3721. The system of claim 3703, further comprising atleast one overburden casing coupled to the first, second, and thirdopenings, wherein at least the one overburden casing is disposed in anoverburden of the formation, and wherein at least the one overburdencasing is further disposed in cement.
 3722. The system of claim 3703,further comprising at least one overburden casing coupled to the first,second, and third openings, wherein at least the one overburden casingis disposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of at least the one overburden casingand the first, second, and third openings.
 3723. The system of claim3703, further comprising at least one overburden casing coupled to thefirst, second, and third openings, wherein at least the one overburdencasing is disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of at least the one overburden casingand the first, second, and third openings, and wherein the packingmaterial is further configured to substantially inhibit a flow of fluidbetween the first, second, and third opening and at least the oneoverburden casing during use.
 3724. The system of claim 3703, whereinthe heated section of the formation is substantially pyrolyzed.
 3725. Asystem configurable to heat a hydrocarbon containing formation,comprising: a first conductor configurable to be disposed in a firstconduit, wherein the first conduit is configurable to be disposed withina first opening in the formation; a second conductor configurable to bedisposed in a second conduit, wherein the second conduit is configurableto be disposed within a second opening in the formation; a thirdconductor configurable to be disposed in a third conduit, wherein thethird conduit is configurable to be disposed within a third opening inthe formation, wherein the first, second, and third conductors arefurther configurable to be electrically coupled in a 3-phase Yconfiguration, and wherein the first, second, and third conductors arefurther configurable to provide heat to at least a portion of theformation during use; and wherein the system is configurable to allowheat to transfer from the first, second, and third conductors to aselected section of the formation during use.
 3726. The system of claim3725, wherein the first, second, and third conductors are furtherconfigurable to generate heat during application of an electricalcurrent to the first conductor.
 3727. The system of claim 3725, whereinthe first, second, and third conductors comprise a pipe.
 3728. Thesystem of claim 3725, wherein the first, second, and third conductorscomprise stainless steel.
 3729. The system of claim 3725, wherein thefirst, second, and third opening comprise a diameter of at leastapproximately 5 cm.
 3730. The system of claim 3725, further comprising afirst sliding electrical connector coupled to the first conductor and asecond sliding electrical connector coupled to the second conductor anda third sliding electrical connector coupled to the third conductor.3731. The system of claim 3725, further comprising a first slidingelectrical connector coupled to the first conductor, wherein the firstsliding electrical connector is further coupled to the first conduit.3732. The system of claim 3725, further comprising a second slidingelectrical connector coupled to the second conductor, wherein the secondsliding electrical connector is further coupled to the second conduit.3733. The system of claim 3725, further comprising a third slidingelectrical connector coupled to the third conductor, wherein the thirdsliding electrical connector is further coupled to the third conduit.3734. The system of claim 3725, wherein each of the first, second, andthird conduits comprises a first section and a second section, wherein athickness of the first section is greater than a thickness of the secondsection such that heat radiated from each of the first, second, andthird conductors to the section along the first section of each of theconduits is less than heat radiated from the first, second, and thirdconductors to the section along the second section of each of theconduits.
 3735. The system of claim 3725, further comprising a fluiddisposed within the first, second, and third conduits, wherein the fluidis configurable to maintain a pressure within the first conduit tosubstantially inhibit deformation of the first, second, and thirdconduits during use.
 3736. The system of claim 3725, further comprisinga thermally conductive fluid disposed within the first, second, andthird conduits.
 3737. The system of claim 3725, further comprising athermally conductive fluid disposed within the first, second, and thirdconduits, wherein the thermally conductive fluid comprises helium. 3738.The system of claim 3725, further comprising a fluid disposed within thefirst, second, and third conduits, wherein the fluid is configurable tosubstantially inhibit arcing between the first, second, and thirdconductors and the first, second, and third conduits during use. 3739.The system of claim 3725, further comprising at least one tube disposedwithin the first, second, and third openings external to the first,second, and third conduits, wherein at least the one tube isconfigurable to remove vapor produced from at least the heated portionof the formation such that a pressure balance is maintained between thefirst, second, and third conduits and the first, second, and thirdopenings to substantially inhibit deformation of the first, second, andthird conduits during use.
 3740. The system of claim 3725, wherein thefirst, second, and third conductors are further configurable to generateradiant heat of approximately 650 W/m to approximately 1650 W/m duringuse.
 3741. The system of claim 3725, further comprising at least oneoverburden casing coupled to the first, second, and third openings,wherein at least the one overburden casing is disposed in an overburdenof the formation.
 3742. The system of claim 3725, further comprising atleast one overburden casing coupled to the first, second, and thirdopenings, wherein at least the one overburden casing is disposed in anoverburden of the formation, and wherein at least the one overburdencasing comprises steel.
 3743. The system of claim 3725, furthercomprising at least one overburden casing coupled to the first, second,and third openings, wherein at least the one overburden casing isdisposed in an overburden of the formation, and wherein at least the oneoverburden casing is further disposed in cement.
 3744. The system ofclaim 3725, further comprising at least one overburden casing coupled tothe first, second, and third openings, wherein at least the oneoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of at least the oneoverburden casing and the first, second, and third openings.
 3745. Thesystem of claim 3725, further comprising at least one overburden casingcoupled to the first, second, and third openings, wherein at least theone overburden casing is disposed in an overburden of the formation,wherein a packing material is disposed at a junction of at least the oneoverburden casing and the first, second, and third openings, and whereinthe packing material is further configurable to substantially inhibit aflow of fluid between the first, second, and third opening and at leastthe one overburden casing during use.
 3746. The system of claim 3725,wherein the heated section of the formation is substantially pyrolyzed.3747. An in situ method for heating a hydrocarbon containing formation,comprising: applying an electrical current to a first conductor toprovide heat to at least a portion of the formation, wherein the firstconductor is disposed in a first conduit, and wherein the first conduitis disposed within a first opening in the formation; applying anelectrical current to a second conductor to provide heat to at least aportion of the formation, wherein the second conductor is disposed in asecond conduit, and wherein the second conduit is disposed within asecond opening in the formation: applying an electrical current to athird conductor to provide heat to at least a portion of the formation,wherein the third conductor is disposed in a third conduit, and whereinthe third conduit is disposed within a third opening in the formation;and allowing the heat to transfer from the first, second, and thirdconductors to a selected section of the formation.
 3748. The method ofclaim 3747, wherein the first, second, and third conductors comprise apipe.
 3749. The method of claim 3747, wherein the first, second, andthird conductors comprise stainless steel.
 3750. The method of claim3747, wherein the first, second, and third conduits comprise stainlesssteel.
 3751. The method of claim 3747, wherein the provided heatcomprises approximately 650 W/m to approximately 1650 W/m.
 3752. Themethod of claim 3747, further comprising determining a temperaturedistribution in the first, second, and third conduits using anelectromagnetic signal provided to the first, second, and thirdconduits.
 3753. The method of claim 3747, further comprising monitoringthe applied electrical current.
 3754. The method of claim 3747, furthercomprising monitoring a voltage applied to the first, second, and thirdconductors.
 3755. The method of claim 3747, further comprisingmonitoring a temperature in the first, second, and third conduits withat least one thermocouple.
 3756. The method of claim 3747, furthercomprising maintaining a sufficient pressure between the first, second,and third conduits and the first, second, and third openings tosubstantially inhibit deformation of the first, second, and thirdconduits.
 3757. The method of claim 3747, further comprising providing athermally conductive fluid within the first, second, and third conduits.3758. The method of claim 3747, further comprising providing a thermallyconductive fluid within the first, second, and third conduits, whereinthe thermally conductive fluid comprises helium.
 3759. The method ofclaim 3747, further comprising inhibiting arcing between the first,second, and third conductors and the first, second, and third conduitswith a fluid disposed within the first, second, and third conduits.3760. The method of claim 3747, further comprising removing a vapor fromthe first, second, and third openings using at least one perforated tubedisposed proximate to the first, second, and third conduits in thefirst, second, and third openings to control a pressure in the first,second, and third openings.
 3761. The method of claim 3747, wherein thefirst, second, and third conduits comprise a first section and a secondsection, wherein a thickness of the first section is greater than athickness of the second section such that heat radiated from the first,second, and third conductors to the section along the first section ofthe first, second, and third conduits is less than heat radiated fromthe first, second, and third conductors to the section along the secondsection of the first, second, and third conduits.
 3762. The method ofclaim 3747, further comprising flowing an oxidizing fluid through anorifice in the first, second, and third conduits.
 3763. The method ofclaim 3747, further comprising heating at least the portion of theformation to substantially pyrolyze at least some of the carbon withinthe formation.
 3764. A system configured to heat a hydrocarboncontaining formation, comprising: a first conductor disposed in aconduit, wherein the conduit is disposed within an opening in theformation; and a second conductor disposed in the conduit, wherein thesecond conductor is electrically coupled to the first conductor with aconnector, and wherein the first and second conductors are configured toprovide heat to at least a portion of the formation during use; andwherein the system is configured to allow heat to transfer from thefirst and second conductors to a selected section of the formationduring use.
 3765. The system of claim 3764, wherein the first conductoris further configured to generate heat during application of anelectrical current to the first conductor.
 3766. The system of claim3764, wherein the first and second conductors comprise a pipe.
 3767. Thesystem of claim 3764, wherein the first and second conductors comprisestainless steel.
 3768. The system of claim 3764, wherein the conduitcomprises stainless steel.
 3769. The system of claim 3764, furthercomprising a centralizer configured to maintain a location of the firstand second conductors within the conduit.
 3770. The system of claim3764, further comprising a centralizer configured to maintain a locationof the first and second conductors within the conduit, wherein thecentralizer comprises ceramic material.
 3771. The system of claim 3764,further comprising a centralizer configured to maintain a location ofthe first and second conductors within the conduit, wherein thecentralizer comprises ceramic material and stainless steel.
 3772. Thesystem of claim 3764, wherein the opening comprises a diameter of atleast approximately 5 cm.
 3773. The system of claim 3764, furthercomprising a lead-in conductor coupled to the first and secondconductors, wherein the lead-in conductor comprises a low resistanceconductor configured to generate substantially no heat.
 3774. The systemof claim 3764, further comprising a lead-in conductor coupled to thefirst and second conductors, wherein the lead-in conductor comprisescopper.
 3775. The system of claim 3764, wherein the conduit comprises afirst section and a second section, wherein a thickness of the firstsection is greater than a thickness of the second section such that heatradiated from the first conductor to the section along the first sectionof the conduit is less than heat radiated from the first conductor tothe section along the second section of the conduit.
 3776. The system ofclaim 3764, further comprising a fluid disposed within the conduit,wherein the fluid is configured to maintain a pressure within theconduit to substantially inhibit deformation of the conduit during use.3777. The system of claim 3764, further comprising a thermallyconductive fluid disposed within the conduit.
 3778. The system of claim3764, further comprising a thermally conductive fluid disposed withinthe conduit, wherein the thermally conductive fluid comprises helium.3779. The system of claim 3764, further comprising a fluid disposedwithin the conduit, wherein the fluid is configured to substantiallyinhibit arcing between the first and second conductors and the conduitduring use.
 3780. The system of claim 3764, further comprising a tubedisposed within the opening external to the conduit, wherein the tube isconfigured to remove vapor produced from at least the heated portion ofthe formation such that a pressure balance is maintained between theconduit and the opening to substantially inhibit deformation of theconduit during use.
 3781. The system of claim 3764, wherein the firstand second conductors are further configured to generate radiant heat ofapproximately 650 W/m to approximately 1650 W/m during use.
 3782. Thesystem of claim 3764, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3783. The system of claim 3764, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3784. The system of claim 3764,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3785. Thesystem of claim 3764, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3786. The system ofclaim 3764, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configured to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3787. The system ofclaim 3764, wherein the heated section of the formation is substantiallypyrolyzed.
 3788. A system configurable to heat a hydrocarbon containingformation, comprising: a first conductor configurable to be disposed ina conduit, wherein the conduit is configurable to be disposed within anopening in the formation; and a second conductor configurable to bedisposed in the conduit, wherein the second conductor is configurable tobe electrically coupled to the first conductor with a connector, andwherein the first and second conductors are further configurable toprovide heat to at least a portion of the formation during use: andwherein the system is configurable to allow heat to transfer from thefirst and second conductors to a selected section of the formationduring use.
 3789. The system of claim 3788, wherein the first conductoris further configurable to generate heat during application of anelectrical current to the first conductor.
 3790. The system of claim3788, wherein the first and second conductors comprise a pipe.
 3791. Thesystem of claim 3788, wherein the first and second conductors comprisestainless steel.
 3792. The system of claim 3788, wherein the conduitcomprises stainless steel.
 3793. The system of claim 3788, furthercomprising a centralizer configurable to maintain a location of thefirst and second conductors within the conduit.
 3794. The system ofclaim 3788, further comprising a centralizer configurable to maintain alocation of the first and second conductors within the conduit, whereinthe centralizer comprises ceramic material.
 3795. The system of claim3788, further comprising a centralizer configurable to maintain alocation of the first and second conductors within the conduit, whereinthe centralizer comprises ceramic material and stainless steel. 3796.The system of claim 3788, wherein the opening comprises a diameter of atleast approximately 5 cm.
 3797. The system of claim 3788, furthercomprising a lead-in conductor coupled to the first and secondconductors, wherein the lead-in conductor comprises a low resistanceconductor configurable to generate substantially no heat.
 3798. Thesystem of claim 3788, further comprising a lead-in conductor coupled tothe first and second conductors, wherein the lead-in conductor comprisescopper.
 3799. The system of claim 3788, wherein the conduit comprises afirst section and a second section, wherein a thickness of the firstsection is greater than a thickness of the second section such that heatradiated from the first conductor to the section along the first sectionof the conduit is less than heat radiated from the first conductor tothe section along the second section of the conduit.
 3800. The system ofclaim 3788, further comprising a fluid disposed within the conduit,wherein the fluid is configurable to maintain a pressure within theconduit to substantially inhibit deformation of the conduit during use.3801. The system of claim 3788, further comprising a thermallyconductive fluid disposed within the conduit.
 3802. The system of claim3788, further comprising a thermally conductive fluid disposed withinthe conduit, wherein the thermally conductive fluid comprises helium.3803. The system of claim 3788, further comprising a fluid disposedwithin the conduit, wherein the fluid is configurable to substantiallyinhibit arcing between the first and second conductors and the conduitduring use.
 3804. The system of claim 3788, further comprising a tubedisposed within the opening external to the conduit, wherein the tube isconfigurable to remove vapor produced from at least the heated portionof the formation such that a pressure balance is maintained between theconduit and the opening to substantially inhibit deformation of theconduit during use.
 3805. The system of claim 3788 wherein the first andsecond conductors are further configurable to generate radiant heat ofapproximately 650 W/m to approximately 1650 W/m during use.
 3806. Thesystem of claim 3788, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3807. The system of claim 3788, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3808. The system of claim 3788,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3809. Thesystem of claim 3788, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3810. The system ofclaim 3788, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configurable to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3811. The system ofclaim 3788, wherein the heated section of the formation is substantiallypyrolyzed.
 3812. An in situ method for heating a hydrocarbon containingformation, comprising: applying an electrical current to at least twoconductors to provide heat to at least a portion of the formation,wherein at least the two conductors are disposed within a conduit,wherein the conduit is disposed within an opening in the formation, andwherein at least the two conductors are electrically coupled with aconnector; and allowing heat to transfer from at least the twoconductors to a selected section of the formation.
 3813. The method ofclaim 3812, wherein at least the two conductors comprise a pipe. 3814.The method of claim 3812 wherein at least the two conductors comprisestainless steel.
 3815. The method of claim 3812, wherein the conduitcomprises stainless steel.
 3816. The method of claim 3812, furthercomprising maintaining a location of at least the two conductors in theconduit with a centralizer.
 3817. The method of claim 3812, furthercomprising maintaining a location of at least the two conductors in theconduit with a centralizer, wherein the centralizer comprises ceramicmaterial.
 3818. The method of claim 3812, further comprising maintaininga location of at least the two conductors in the conduit with acentralizer, wherein the centralizer comprises ceramic material andstainless steel.
 3819. The method of claim 3812, wherein the providedheat comprises approximately 650 W/m to approximately 1650 W/m. 3820.The method of claim 3812, further comprising determining a temperaturedistribution in the conduit using an electromagnetic signal provided tothe conduit.
 3821. The method of claim 3812 further comprisingmonitoring the applied electrical current.
 3822. The method of claim3812, further comprising monitoring a voltage applied to at least thetwo conductors.
 3823. The method of claim 3812, further comprisingmonitoring a temperature in the conduit with at least one thermocouple.3824. The method of claim 3812 further comprising coupling an overburdencasing to the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3825. The method of claim 3812, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3826. The method of claim3812, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3827. The method of claim 3812, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of the overburden casing and theopening.
 3828. The method of claim 3812, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the methodfurther comprises inhibiting a flow of fluid between the opening and theoverburden casing with a packing material.
 3829. The method of claim3812, further comprising maintaining a sufficient pressure between theconduit and the formation to substantially inhibit deformation of theconduit.
 3830. The method of claim 3812, further comprising providing athermally conductive fluid within the conduit.
 3831. The method of claim3812, further comprising providing a thermally conductive fluid withinthe conduit, wherein the thermally conductive fluid comprises helium.3832. The method of claim 3812, further comprising inhibiting arcingbetween at least the two conductors and the conduit with a fluiddisposed within the conduit.
 3833. The method of claim 3812, furthercomprising removing a vapor from the opening using a perforated tubedisposed proximate to the conduit in the opening to control a pressurein the opening.
 3834. The method of claim 3812, further comprisingflowing a corrosion inhibiting fluid through a perforated tube disposedproximate to the conduit in the opening.
 3835. The method of claim 3812,wherein the conduit comprises a first section and a second section,wherein a thickness of the first section is greater than a thickness ofthe second section such that heat radiated from the first conductor tothe section along the first section of the conduit is less than heatradiated from the first conductor to the section along the secondsection of the conduit.
 3836. The method of claim 3812 furthercomprising flowing an oxidizing fluid through an orifice in the conduit.3837. The method of claim 3812, further comprising disposing aperforated tube proximate to the conduit and flowing an oxidizing fluidthrough the perforated tube.
 3838. The method of claim 3812 furthercomprising heating at least the portion of the formation tosubstantially pyrolyze at least some of the carbon within the formation.3839. A system configured to heat a hydrocarbon containing formationcomprising: at least one conductor disposed in a conduit, wherein theconduit is disposed within an opening in the formation, and wherein atleast the one conductor is configured to provide heat to at least afirst portion of the formation during use; at least one slidingconnector, wherein at least the one sliding connector is coupled to atleast the one conductor, wherein at least the one sliding connector isto configured to provide heat during use, and wherein heat provided byat least the one sliding connector is substantially less than the heatprovided by at least the one conductor during use; and wherein thesystem is configured to allow heat to transfer from at least the oneconductor to a section of the formation during use.
 3840. The system ofclaim 3839, wherein at least the one conductor is further configured togenerate heat during application of an electrical current to at leastthe one conductor.
 3841. The system of claim 3839, wherein at least theone conductor comprises a pipe.
 3842. The system of claim 3839, whereinat least the one conductor comprises stainless steel.
 3843. The systemof claim 3839, wherein the conduit comprises stainless steel.
 3844. Thesystem of claim 3839, further comprising a centralizer configured tomaintain a location of at least the one conductor within the conduit.3845. The system of claim 3839, further comprising a centralizerconfigured to maintain a location of at least the one conductor withinthe conduit, wherein the centralizer comprises ceramic material. 3846.The system of claim 3839, further comprising a centralizer configured tomaintain a location of at least the one conductor within the conduit,wherein the centralizer comprises ceramic material and stainless steel.3847. The system of claim 3839, wherein the opening comprises a diameterof at least approximately 5 cm.
 3848. The system of claim 3839, furthercomprising a lead-in conductor coupled to at least the one conductor,wherein the lead-in conductor comprises a low resistance conductorconfigured to generate substantially no heat.
 3849. The system of claim3839, further comprising a lead-in conductor coupled to at least the oneconductor, wherein the lead-in conductor comprises copper.
 3850. Thesystem of claim 3839, wherein the conduit comprises a first section anda second section, wherein a thickness of the first section is greaterthan a thickness of the second section such that heat radiated from thefirst conductor to the section along the first section of the conduit isless than heat radiated from the first conductor to the section alongthe second section of the conduit.
 3851. The system of claim 3839,further comprising a fluid disposed within the conduit, wherein thefluid is configured to maintain a pressure within the conduit tosubstantially inhibit deformation of the conduit during use.
 3852. Thesystem of claim 3839, further comprising a thermally conductive fluiddisposed within the conduit.
 3853. The system of claim 3839, furthercomprising a thermally conductive fluid disposed within the conduit,wherein the thermally conductive fluid comprises helium.
 3854. Thesystem of claim 3839, further comprising a fluid disposed within theconduit, wherein the fluid is configured to substantially inhibit arcingbetween at least the one conductor and the conduit during use.
 3855. Thesystem of claim 3839, further comprising a tube disposed within theopening external to the conduit, wherein the tube is configured toremove vapor produced from at least the heated portion of the formationsuch that a pressure balance is maintained between the conduit and theopening to substantially inhibit deformation of the conduit during use.3856. The system of claim 3839, wherein at least the one conductor isfurther configured to generate radiant heat of approximately 650 W/m toapproximately 1650 W/m during use.
 3857. The system of claim 3839,further comprising an overburden casing coupled to the opening, whereinthe overburden casing, is disposed in an overburden of the formation.3858. The system of claim 3839, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 3859. The system of claim 3839, further comprising an overburdencasing coupled to the opening, wherein the overburden casing is disposedin an overburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3860. The system of claim 3839, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3861. The system of claim 3839, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening and wherein the packing material is further configuredto substantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3862. The system of claim 3839, furthercomprising an overburden casing coupled to the opening and asubstantially low resistance conductor disposed within the overburdencasing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor.
 3863. The system ofclaim 3839, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3864. Thesystem of claim 3839, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configured to support thesubstantially low resistance conductor within the overburden casing.3865. The system of claim 3839, wherein the heated section of theformation is substantially pyrolyzed.
 3866. A system configurable toheat a hydrocarbon containing formation, comprising: at least oneconductor configurable to be disposed in a conduit, wherein the conduitis configurable to be disposed within an opening in the formation, andwherein at least the one conductor is further configurable to provideheat to at least a first portion of the formation during use; at leastone sliding connector, wherein at least the one sliding connector isconfigurable to be coupled to at least the one conductor, wherein atleast the one sliding connector is further configurable to provide heatduring use, and wherein heat provided by at least the one slidingconnector is substantially less than the heat provided by at least theone conductor during use; and wherein the system is configurable toallow heat to transfer from at least the one conductor to a section ofthe formation during use.
 3867. The system of claim 3866, wherein atleast the one conductor is further configurable to generate heat duringapplication of an electrical current to at least the one conductor.3868. The system of claim 3866, wherein at least the one conductorcomprises a pipe.
 3869. The system of claim 3866, wherein at least theone conductor comprises stainless steel.
 3870. The system of claim 3866,wherein the conduit comprises stainless steel.
 3871. The system of claim3866 further comprising a centralizer configurable to maintain alocation of at least the one conductor within the conduit.
 3872. Thesystem of claim 3866, further comprising a centralizer configurable tomaintain a location of at least the one conductor within the conduit,wherein the centralizer comprises ceramic material.
 3873. The system ofclaim 3866, further comprising a centralizer configurable to maintain alocation of at least the one conductor within the conduit, wherein thecentralizer comprises ceramic material and stainless steel.
 3874. Thesystem of claim 3866, wherein the opening comprises a diameter of atleast approximately 5 cm.
 3875. The system of claim 3866, furthercomprising a lead-in conductor coupled to at least the one conductor,wherein the lead-in conductor comprises a low resistance conductorconfigurable to generate substantially no heat.
 3876. The system ofclaim 3866, further comprising a lead-in conductor coupled to at leastthe one conductor, wherein the lead-in conductor comprises copper. 3877.The system of claim 3866, wherein the conduit comprises a first sectionand a second section, wherein a thickness of the first section isgreater than a thickness of the second section such that heat radiatedfrom the first conductor to the section along the first section of theconduit is less than heat radiated from the first conductor to thesection along the second section of the conduit.
 3878. The system ofclaim 3866, further comprising a fluid disposed within the conduit,wherein the fluid is configurable to maintain a pressure within theconduit to substantially inhibit deformation of the conduit during use.3879. The system of claim 3866, further comprising a thermallyconductive fluid disposed within the conduit.
 3880. The system of claim3866, further comprising a thermally conductive fluid disposed withinthe conduit, wherein the thermally conductive fluid comprises helium.3881. The system of claim 3866, further comprising a fluid disposedwithin the conduit, wherein the fluid is configurable to substantiallyinhibit arcing between at least the one conductor and the conduit duringuse.
 3882. The system of claim 3866 further comprising a tube disposedwithin the opening external to the conduit, wherein the tube isconfigurable to remove vapor produced from at least the heated portionof the formation such that a pressure balance is maintained between theconduit and the opening to substantially inhibit deformation of theconduit during use.
 3883. The system of claim 3866, wherein at least theone conductor is further configurable to generate radiant heat ofapproximately 650 W/m to approximately 1650 W/m during use.
 3884. Thesystem of claim 3866, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3885. The system of claim 3866, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3886. The system of claim 3866,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3887. Thesystem of claim 3866, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3888. The system ofclaim 3866, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialis further configurable to substantially inhibit a flow of fluid betweenthe opening and the overburden casing during use.
 3889. The system ofclaim 3866, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor.
 3890. The system ofclaim 3866, further comprising an overburden casing coupled to theopening and a substantially low resistance conductor disposed within theoverburden casing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor, and wherein thesubstantially low resistance conductor comprises carbon steel.
 3891. Thesystem of claim 3866, further comprising an overburden casing coupled tothe opening and a substantially low resistance conductor disposed withinthe overburden casing and a centralizer configurable to support thesubstantially low resistance conductor within the overburden casing.3892. The system of claim 3866, wherein the heated section of theformation is substantially pyrolyzed.
 3893. An in situ method forheating a hydrocarbon containing formation, comprising: applying anelectrical current to at least one conductor and at least one slidingconnector to provide heat to at least a portion of the formation,wherein at least the one conductor and at least the one slidingconnector are disposed within a conduit, and wherein heat provided by atleast the one conductor is substantially greater than heat provided byat least the one sliding connector; and allowing the heat to transferfrom at least the one conductor and at least the one sliding connectorto a section of the formation.
 3894. The method of claim 3893, whereinat least the one conductor comprises a pipe.
 3895. The method of claim3893, wherein at least the one conductor comprises stainless steel.3896. The method of claim 3893, wherein the conduit comprises stainlesssteel.
 3897. The method of claim 3893, further comprising maintaining alocation of at least the one conductor in the conduit with acentralizer.
 3898. The method of claim 3893, further comprisingmaintaining a location of at least the one conductor in the conduit witha centralizer, wherein the centralizer comprises ceramic material. 3899.The method of claim 3893, further comprising maintaining a location ofat least the one conductor in the conduit with a centralizer, whereinthe centralizer comprises ceramic material and stainless steel. 3900.The method of claim 3893, wherein the provided heat comprisesapproximately 650 W/m to approximately 1650 W/m.
 3901. The method ofclaim 3893, further comprising determining a temperature distribution inthe conduit using an electromagnetic signal provided to the conduit.3902. The method of claim 3893, further comprising monitoring theapplied electrical current.
 3903. The method of claim 3893, furthercomprising monitoring a voltage applied to at least the one conductor.3904. The method of claim 3893, further comprising monitoring atemperature in the conduit with at least one thermocouple.
 3905. Themethod of claim 3893, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 3906. The method of claim 3893, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein the overburden casing comprises steel.
 3907. The method of claim3893, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 3908. The method of claim 3893, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein a packingmaterial is disposed at a junction of the overburden casing and theopening.
 3909. The method of claim 3893, further comprising coupling anoverburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the methodfurther comprises inhibiting a flow of fluid between the opening and theoverburden casing with a packing material.
 3910. The method of claim3893, further comprising coupling an overburden casing to the opening,wherein a substantially low resistance conductor is disposed within theoverburden casing, and wherein the substantially low resistanceconductor is electrically coupled to at least the one conductor. 3911.The method of claim 3893, further comprising coupling an overburdencasing to the opening, wherein a substantially low resistance conductoris disposed within the overburden casing, wherein the substantially lowresistance conductor is electrically coupled to at least the oneconductor, and wherein the substantially low resistance conductorcomprises carbon steel.
 3912. The method of claim 3893, furthercomprising coupling an overburden casing to the opening, wherein asubstantially low resistance conductor is disposed within the overburdencasing, wherein the substantially low resistance conductor iselectrically coupled to at least the one conductor, and wherein themethod further comprises maintaining a location of the substantially lowresistance conductor in the overburden casing with a centralizersupport.
 3913. The method of claim 3893, further comprising electricallycoupling a lead-in conductor to at least the one conductor, wherein thelead-in conductor comprises a low resistance conductor configured togenerate substantially no heat.
 3914. The method of claim 3893, furthercomprising electrically coupling a lead-in conductor to at least the oneconductor, wherein the lead-in conductor comprises copper.
 3915. Themethod of claim 3893, further comprising maintaining a sufficientpressure between the conduit and the formation to substantially inhibitdeformation of the conduit.
 3916. The method of claim 3893, furthercomprising providing a thermally conductive fluid within the conduit.3917. The method of claim 3893, further comprising providing a thermallyconductive fluid within the conduit, wherein the thermally conductivefluid comprises helium.
 3918. The method of claim 3893, furthercomprising inhibiting arcing between the conductor and the conduit witha fluid disposed within the conduit.
 3919. The method of claim 3893,further comprising removing a vapor from the opening using a perforatedtube disposed proximate to the conduit in the opening to control apressure in the opening.
 3920. The method of claim 3893, furthercomprising flowing a corrosion inhibiting fluid through a perforatedtube disposed proximate to the conduit in the opening.
 3921. The methodof claim 3893, further comprising flowing an oxidizing fluid through anorifice in the conduit.
 3922. The method of claim 3893, furthercomprising disposing a perforated tube proximate to the conduit andflowing an oxidizing fluid through the perforated tube.
 3923. The methodof claim 3893, further comprising heating at least the portion of theformation to substantially pyrolyze at least some of the carbon withinthe formation.
 3924. A system configured to heat a hydrocarboncontaining formation, comprising: at least one elongated member disposedwithin an opening in the formation, wherein at least the one elongatedmember is configured to provide heat to at least a portion of theformation during use; and wherein the system is configured to allow heatto transfer from at least the one elongated member to a section of theformation during use.
 3925. The system of claim 3924, wherein at leastthe one elongated member comprises stainless steel.
 3926. The system ofclaim 3924, wherein at least the one elongated member is furtherconfigured to generate heat during application of an electrical currentto at least the one elongated member.
 3927. The system of claim 3924,further comprising a support member coupled to at least the oneelongated member, wherein the support member is configured to support atleast the one elongated member.
 3928. The system of claim 3924, furthercomprising a support member coupled to at least the one elongatedmember, wherein the support member is configured to support at least theone elongated member, and wherein the support member comprises openings.3929. The system of claim 3924, further comprising a support membercoupled to at least the one elongated member, wherein the support memberis configured to support at least the one elongated member, wherein thesupport member comprises openings, wherein the openings are configuredto flow a fluid along a length of at least the one elongated memberduring use, and wherein the fluid is configured to substantially inhibitcarbon deposition on or proximate to at least the one elongated memberduring use.
 3930. The system of claim 3924, further comprising a tubedisposed in the opening, wherein the tube comprises openings, whereinthe openings are configured to flow a fluid along a length of at leastthe one elongated member during use, and wherein the fluid is configuredto substantially inhibit carbon deposition on or proximate to at leastthe one elongated member during use.
 3931. The system of claim 3924,further comprising a centralizer coupled to at least the one elongatedmember, wherein the centralizer is configured to electrically isolate atleast the one elongated member.
 3932. The system of claim 3924, furthercomprising a centralizer coupled to at least the one elongated memberand a support member coupled to at least the one elongated member,wherein the centralizer is configured to maintain a location of at leastthe one elongated member on the support member.
 3933. The system ofclaim 3924, wherein the opening comprises a diameter of at leastapproximately 5 cm.
 3934. The system of claim 3924, further comprising alead-in conductor coupled to at least the one elongated member, whereinthe lead-in conductor comprises a low resistance conductor configured togenerate substantially no heat.
 3935. The system of claim 3924, furthercomprising a lead-in conductor coupled to at least the one elongatedmember, wherein the lead-in conductor comprises a rubber insulatedconductor.
 3936. The system of claim 3924, further comprising a lead-inconductor coupled to at least the one elongated member, wherein thelead-in conductor comprises copper wire.
 3937. The system of claim 3924,further comprising a lead-in conductor coupled to at least the oneelongated member with a cold pin transition conductor.
 3938. The systemof claim 3924, further comprising a lead-in conductor coupled to atleast the one elongated member with a cold pin transition conductor,wherein the cold pin transition conductor comprises a substantially lowresistance insulated conductor.
 3939. The system of claim 3924, whereinat least the one elongated member is arranged in a series electricalconfiguration.
 3940. The system of claim 3924 wherein at least the oneelongated member is arranged in a parallel electrical configuration.3941. The system of claim 3924, wherein at least the one elongatedmember is configured to generate radiant heat of approximately 650 W/mto approximately 1650 W/m during use.
 3942. The system of claim 3924,further comprising a perforated tube disposed in the opening external toat least the one elongated member, wherein the perforated tube isconfigured to remove vapor from the opening to control a pressure in theopening during use.
 3943. The system of claim 3924, further comprisingan overburden casing coupled to the opening, wherein the overburdencasing is disposed in an overburden of the formation.
 3944. The systemof claim 3924, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, and wherein the overburden casing comprises steel. 3945.The system of claim 3924, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 3946. The system of claim 3924, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, andwherein a packing material is disposed at a junction of the overburdencasing and the opening.
 3947. The system of claim 3924, furthercomprising an overburden casing coupled to the opening, wherein theoverburden casing is disposed in an overburden of the formation, whereina packing material is disposed at a junction of the overburden casingand the opening, and wherein the packing material comprises cement.3948. The system of claim 3924, further comprising an overburden casingcoupled to the opening, wherein the overburden casing is disposed in anoverburden of the formation, wherein a packing material is disposed at ajunction of the overburden casing and the opening, and wherein thepacking material is further configured to substantially inhibit a flowof fluid between the opening and the overburden casing during use. 3949.The system of claim 3924, wherein the heated section of the formation issubstantially pyrolyzed.
 3950. A system configurable to heat ahydrocarbon containing formation, comprising: at least one elongatedmember configurable to be disposed within an opening in the formation,wherein at least the one elongated member is further configurable toprovide heat to at least a portion of the formation during use, andwherein the system is configurable to allow heat to transfer from atleast the one elongated member to a section of the formation during use.3951. The system of claim 3950, wherein at least the one elongatedmember comprises stainless steel.
 3952. The system of claim 3950,wherein at least the one elongated member is further configurable togenerate heat during application of an electrical current to at leastthe one elongated member.
 3953. The system of claim 3950, furthercomprising a support member coupled to at least the one elongatedmember, wherein the support member is configurable to support at leastthe one elongated member.
 3954. The system of claim 3950, furthercomprising a support member coupled to at least the one elongatedmember, wherein the support member is configurable to support at leastthe one elongated member, and wherein the support member comprisesopenings.
 3955. The system of claim 3950, further comprising a supportmember coupled to at least the one elongated member, wherein the supportmember is configurable to support at least the one elongated member,wherein the support member comprises openings, wherein the openings areconfigurable to flow a fluid along a length of at least the oneelongated member during use, and wherein the fluid is configurable tosubstantially inhibit carbon deposition on or proximate to at least theone elongated member during use.
 3956. The system of claim 3950, furthercomprising a tube disposed in the opening, wherein the tube comprisesopenings, wherein the openings are configurable to flow a fluid along alength of at least the one elongated member during use, and wherein thefluid is configurable to substantially inhibit carbon deposition on orproximate to at least the one elongated member during use.
 3957. Thesystem of claim 3950, further comprising a centralizer coupled to atleast the one elongated member, wherein the centralizer is configurableto electrically isolate at least the one elongated member.
 3958. Thesystem of claim 3950, further comprising a centralizer coupled to atleast the one elongated member and a support member coupled to at leastthe one elongated member, wherein the centralizer is configurable tomaintain a location of at least the one elongated member on the supportmember.
 3959. The system of claim 3950, wherein the opening comprises adiameter of at least approximately 5 cm.
 3960. The system of claim 3950,further comprising a lead-in conductor coupled to at least the oneelongated member, wherein the lead-in conductor comprises a lowresistance conductor configurable to generate substantially no heat.3961. The system of claim 3950, further comprising a lead-in conductorcoupled to at least the one elongated member, wherein the lead-inconductor comprises a rubber insulated conductor.
 3962. The system ofclaim 3950, further comprising a lead-in conductor coupled to at leastthe one elongated member, wherein the lead-in conductor comprises copperwire.
 3963. The system of claim 3950, further comprising a lead-inconductor coupled to at least the one elongated member with a cold pintransition conductor.
 3964. The system of claim 3950, further comprisinga lead-in conductor coupled to at least the one elongated member with acold pin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 3965. Thesystem of claim 3950, wherein at least the one elongated member isarranged in a series electrical configuration.
 3966. The system of claim3950, wherein at least the one elongated member is arranged in aparallel electrical configuration.
 3967. The system of claim 3950,wherein at least the one elongated member is configurable to generateradiant heat of approximately 650 W/m to approximately 1650 W/m duringuse.
 3968. The system of claim 3950, further comprising a perforatedtube disposed in the opening external to at least the one elongatedmember, wherein the perforated tube is configurable to remove vapor fromthe opening to control a pressure in the opening during use.
 3969. Thesystem of claim 3950, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 3970. The system of claim 3950, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 3971. The system of claim 3950,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 3972. Thesystem of claim 3950, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 3973. The system ofclaim 3950, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialcomprises cement.
 3974. The system of claim 3950, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is further configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 3975. The system of claim 3950, whereinthe heated section of the formation is substantially pyrolyzed.
 3976. Anin situ method for heating a hydrocarbon containing formation,comprising: applying an electrical current to at least one elongatedmember to provide heat to at least a portion of the formation, whereinat least the one elongated member is disposed within an opening of theformation; and allowing heat to transfer from at least the one elongatedmember to a section of the formation.
 3977. The method of claim 3976,wherein at least the one elongated member comprises a metal strip. 3978.The method of claim 3976, wherein at least the one elongated membercomprises a metal rod.
 3979. The method of claim 3976, wherein at leastthe one elongated member comprises stainless steel.
 3980. The method ofclaim 3976, further comprising supporting at least the one elongatedmember on a center support member.
 981. The method of claim 3976,further comprising supporting at least the one elongated member on acenter support member, wherein the center support member comprises atube.
 3982. The method of claim 3976, further comprising electricallyisolating at least the one elongated member with a centralizer. 3983.The method of claim 3976, further comprising laterally spacing at leastthe one elongated member with a centralizer.
 3984. The method of claim3976, further comprising electrically coupling at least the oneelongated member in a series configuration.
 3985. The method of claim3976, further comprising electrically coupling at least the oneelongated member in a parallel configuration.
 3986. The method of claim3976 wherein the provided heat comprises approximately 650 W/m toapproximately 1650 W/m.
 3987. The method of claim 3976, furthercomprising determining a temperature distribution in at least the oneelongated member using an electromagnetic signal provided to at leastthe one elongated member.
 3988. The method of claim 3976, furthercomprising monitoring the applied electrical current.
 3989. The methodof claim 3976, further comprising monitoring a voltage applied to atleast the one elongated member.
 3990. The method of claim 3976, furthercomprising monitoring a temperature in at least the one elongated memberwith at least one thermocouple.
 3991. The method of claim 3976, furthercomprising supporting at least the one elongated member on a centersupport member, wherein the center support member comprises openings,the method further comprising flowing an oxidizing fluid through theopenings to substantially inhibit carbon deposition proximate to or onat least the one elongated member.
 3992. The method of claim 3976,further comprising flowing an oxidizing fluid through a tube disposedproximate to at least the one elongated member to substantially inhibitcarbon deposition proximate to or on at least the one elongated member.3993. The method of claim 3976, further comprising flowing an oxidizingfluid through an opening in at least the one elongated member tosubstantially inhibit carbon deposition proximate to or on at least theone elongated member.
 3994. The method of claim
 3976. further comprisingelectrically coupling a lead-in conductor to at least the one elongatedmember, wherein the lead-in conductor comprises a low resistanceconductor configured to generate substantially no heat.
 3995. The methodof claim 3976, further comprising electrically coupling a lead-inconductor to at least the one elongated member using a cold pintransition conductor.
 3996. The method of claim 3976, further comprisingelectrically coupling a lead-in conductor to at least the one elongatedmember using a cold pin transition conductor, wherein the cold pintransition conductor comprises a substantially low resistance insulatedconductor.
 3997. The method of claim 3976, further comprising couplingan overburden casing to the opening, wherein the overburden casing isdisposed in an overburden of the formation.
 3998. The method of claim3976, further comprising coupling an overburden casing to the opening,wherein the overburden casing comprises steel.
 3999. The method of claim3976, further comprising coupling an overburden casing to the opening,wherein the overburden casing is disposed in cement.
 4000. The method ofclaim 3976, further comprising coupling an overburden casing to theopening, wherein a packing material is disposed at a junction of theoverburden casing and the opening.
 4001. The method of claim 3976,further comprising coupling an overburden casing to the opening, whereina packing material is disposed at a junction of the overburden casing,and the opening, and wherein the method further comprises inhibiting aflow of fluid between the opening and the overburden casing with thepacking material.
 4002. The method of claim 3976, further comprisingheating at least the portion of the formation to substantially pyrolyzeat least some of the carbon within the formation.
 4003. A systemconfigured to heat a hydrocarbon containing formation, comprising: atleast one elongated member disposed within an opening in the formation,wherein at least the one elongated member is configured to provide heatto at least a portion of the formation during use; an oxidizing fluidsource; a conduit disposed within the opening, wherein the conduit isconfigured to provide an oxidizing fluid from the oxidizing fluid sourceto the opening during use, and wherein the oxidizing fluid is selectedto substantially inhibit carbon deposition on or proximate to at leastthe one elongated member during use; and wherein the system isconfigured to allow heat to transfer from at least the one elongatedmember to a section of the formation during use.
 4004. The system ofclaim 4003, wherein at least the one elongated member comprisesstainless steel.
 4005. The system of claim 4003, wherein at least theone elongated member is further configured to generate heat duringapplication of an electrical current to at least the one elongatedmember.
 4006. The system of claim 4003, wherein at least the oneelongated member is coupled to the conduit, wherein the conduit isfurther configured to support at least the one elongated member. 4007.The system of claim 4003, wherein at least the one elongated member iscoupled to the conduit, wherein the conduit is further configured tosupport at least the one elongated member, and wherein the conduitcomprises openings.
 4008. The system of claim 4003, further comprising acentralizer coupled to at least the one elongated member and theconduit, wherein the centralizer is configured to electrically isolateat least the one elongated member from the conduit.
 4009. The system ofclaim 4003, further comprising a centralizer coupled to at least the oneelongated member and the conduit, wherein the centralizer is configuredto maintain a location of at least the one elongated member on theconduit.
 4010. The system of claim 4003, wherein the opening comprises adiameter of at least approximately 5 cm.
 4011. The system of claim 4003,further comprising a lead-in conductor coupled to at least the oneelongated member, wherein the lead-in conductor comprises a lowresistance conductor configured to generate substantially no heat. 4012.The system of claim 4003, further comprising a lead-in conductor coupledto at least the one elongated member, wherein the lead-in conductorcomprises a rubber insulated conductor.
 4013. The system of claim 4003,further comprising a lead-in conductor coupled to at least the oneelongated member, wherein the lead-in conductor comprises copper wire.4014. The system of claim 4003, further comprising a lead-in conductorcoupled to at least the one elongated member with a cold pin transitionconductor.
 4015. The system of claim 4003, further comprising a lead-inconductor coupled to at least the one elongated member with a cold pintransition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor .
 4016. Thesystem of claim 4003, wherein at least the one elongated member isarranged in a series electrical configuration.
 4017. The system of claim4003, wherein at least the one elongated member is arranged in aparallel electrical configuration.
 4018. The system of claim 4003,wherein at least the one elongated member is configured to generateradiant heat of approximately 650 W/m to approximately 1650 W/m duringuse.
 4019. The system of claim 4003, further comprising a perforatedtube disposed in the opening external to at least the one elongatedmember, wherein the perforated tube is configured to remove vapor fromthe opening to control a pressure in the opening during use.
 4020. Thesystem of claim 4003, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 4021. The system of claim 4003, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 4022. The system of claim 4003,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing, is further disposed in cement.
 4023. Thesystem of claim 4003, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 4024. The system ofclaim 4003, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialcomprises cement.
 4025. The system of claim 4003, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is further configured tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 4026. The system of claim 4003, whereinthe heated section of the formation is substantially pyrolyzed.
 4027. Asystem configurable to heat a hydrocarbon containing formation,comprising: at least one elongated member configurable to be disposedwithin an opening in the formation, wherein at least the one elongatedmember is further configurable to provide heat to at least a portion ofthe formation during use; a conduit configurable to be disposed withinthe opening, wherein the conduit is further configurable to provide anoxidizing fluid from the oxidizing fluid source to the opening duringuse, and wherein the system is configurable to allow the oxidizing fluidto substantially inhibit carbon deposition on or proximate to at leastthe one elongated member during use; and wherein the system is furtherconfigurable to allow heat to transfer from at least the one elongatedmember to a section of the formation during use.
 4028. The system ofclaim 4027, wherein at least the one elongated member comprisesstainless steel.
 4029. The system of claim 4027, wherein at least theone elongated member is further configurable to generate heat duringapplication of an electrical current to at least the one elongatedmember.
 4030. The system of claim 4027, wherein at least the oneelongated member is coupled to the conduit, wherein the conduit isfurther configurable to support at least the one elongated member. 4031.The system of claim 4027, wherein at least the one elongated member iscoupled to the conduit, wherein the conduit is further configurable tosupport at least the one elongated member and wherein the conduitcomprises openings.
 4032. The system of claim 4027, further comprising acentralizer coupled to at least the one elongated member and theconduit, wherein the centralizer is configurable to electrically isolateat least the one elongated member from the conduit.
 4033. The system ofclaim 4027, further comprising a centralizer coupled to at least the oneelongated member and the conduit, wherein the centralizer isconfigurable to maintain a location of at least the one elongated memberon the conduit.
 4034. The system of claim 4027, wherein the openingcomprises a diameter of at least approximately 5 cm.
 4035. The system ofclaim 4027, further comprising a lead-in conductor coupled to at leastthe one elongated member, wherein the lead-in conductor comprises a lowresistance conductor configurable to generate substantially no heat.4036. The system of claim 4027, further comprising a lead-in conductorcoupled to at least the one elongated member, wherein the lead-inconductor comprises a rubber insulated conductor.
 4037. The system ofclaim 4027, further comprising a lead-in conductor coupled to at leastthe one elongated member, wherein the lead-in conductor comprises copperwire.
 4038. The system of claim 4027, further comprising a lead-inconductor coupled to at least the one elongated member with a cold pintransition conductor.
 4039. The system of claim 4027, further comprisinga lead-in conductor coupled to at least the one elongated member with acold pin transition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 4040. Thesystem of claim 4027, wherein at least the one elongated member isarranged in a series electrical configuration.
 4041. The system of claim4027, wherein at least the one elongated member is arranged in aparallel electrical configuration.
 4042. The system of claim 4027,wherein at least the one elongated member is configurable to generateradiant heat of approximately 650 W/m to approximately 1650 W/m duringuse.
 4043. The system of claim 4027, further comprising a perforatedtube disposed in the opening external to at least the one elongatedmember, wherein the perforated tube is configurable to remove vapor fromthe opening to control a pressure in the opening during use.
 4044. Thesystem of claim 4027, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation.
 4045. The system of claim 4027, further comprising anoverburden casing coupled to the opening, wherein the overburden casingis disposed in an overburden of the formation, and wherein theoverburden casing comprises steel.
 4046. The system of claim 4027,further comprising an overburden casing coupled to the opening, whereinthe overburden casing is disposed in an overburden of the formation, andwherein the overburden casing is further disposed in cement.
 4047. Thesystem of claim 4027, further comprising an overburden casing coupled tothe opening, wherein the overburden casing is disposed in an overburdenof the formation, and wherein a packing material is disposed at ajunction of the overburden casing and the opening.
 4048. The system ofclaim 4027, further comprising an overburden casing coupled to theopening, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the opening, and wherein the packing materialcomprises cement.
 4049. The system of claim 4027, further comprising anoverburden casing coupled to the opening wherein the overburden casingis disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and theopening, and wherein the packing material is further configurable tosubstantially inhibit a flow of fluid between the opening and theoverburden casing during use.
 4050. The system of claim 4027, whereinthe heated section of the formation is substantially pyrolyzed.
 4051. Anin situ method for heating a hydrocarbon containing formation,comprising: applying an electrical current to at least one elongatedmember to provide heat to at least a portion of the formation, whereinat least the one elongated member is disposed within an opening in theformation; providing an oxidizing fluid to at least the one elongatedmember to substantially inhibit carbon deposition on or proximate to atleast the one elongated member; and allowing heat to transfer from atleast the one elongated member to a section of the formation.
 4052. Themethod of claim 4051, wherein at least the one elongated membercomprises a metal strip.
 4053. The method of claim 4051, wherein atleast the one elongated member comprises a metal rod.
 4054. The methodof claim 4051, wherein at least the one elongated member comprisesstainless steel.
 4055. The method of claim 4051, further comprisingsupporting at least the one elongated member on a center support member.4056. The method of claim 4051, further comprising supporting at leastthe one elongated member on a center support member, wherein the centersupport member comprises a tube.
 4057. The method of claim 4051, furthercomprising electrically isolating at least the one elongated member witha centralizer.
 4058. The method of claim 4051, further comprisinglaterally spacing at least the one elongated member with a centralizer.4059. The method of claim 4051, further comprising electrically couplingat least the one elongated member in a series configuration.
 4060. Themethod of claim 4051, further comprising electrically coupling at leastthe one elongated member in a parallel configuration.
 4061. The methodof claim 4051, wherein the provided heat comprises approximately 650 W/mto approximately 1650 W/m.
 4062. The method of claim 4051, furthercomprising determining a temperature distribution in at least the oneelongated member using an electromagnetic signal provided to at leastthe one elongated member.
 4063. The method of claim 4051, furthercomprising monitoring the applied electrical current.
 4064. The methodof claim 4051, further comprising monitoring a voltage applied to atleast the one elongated member.
 4065. The method of claim 4051, furthercomprising monitoring a temperature in at least the one elongated memberwith at least one thermocouple.
 4066. The method of claim 4051, furthercomprising supporting at least the one elongated member on a centersupport member, wherein the center support member comprises openings,wherein providing the oxidizing fluid to at least the one elongatedmember comprises flowing the oxidizing fluid through the openings in thecenter support member.
 4067. The method of claim 4051, wherein providingthe oxidizing fluid to at least the one elongated member comprisesflowing the oxidizing fluid through orifices in a tube disposed in theopening proximate to at least the one elongated member.
 4068. The methodof claim 4051, further comprising electrically coupling a lead-inconductor to at least the one elongated member, wherein the lead-inconductor comprises a low resistance conductor configured to generatesubstantially no heat.
 4069. The method of claim 4051, furthercomprising electrically coupling a lead-in conductor to at least the oneelongated member using a cold pin transition conductor.
 4070. The methodof claim 4051, further comprising electrically coupling a lead-inconductor to at least the one elongated member using a cold pintransition conductor, wherein the cold pin transition conductorcomprises a substantially low resistance insulated conductor.
 4071. Themethod of claim 4051, further comprising coupling an overburden casingto the opening, wherein the overburden casing is disposed in anoverburden of the formation.
 4072. The method of claim 4051, furthercomprising coupling an overburden casing to the opening, wherein theoverburden casing comprises steel.
 4073. The method of claim 4051,further comprising coupling an overburden casing to the opening, whereinthe overburden casing is disposed in cement.
 4074. The method of claim4051, further comprising coupling an overburden casing to the opening,wherein a packing material is disposed at a junction of the overburdencasing and the opening.
 4075. The method of claim 4051, furthercomprising coupling an overburden casing to the opening, wherein apacking material is disposed at a junction of the overburden casing andthe opening, and wherein the me hod further comprises inhibiting a flowof fluid between the opening and the overburden casing with the packingmaterial.
 4076. The method of claim 4051, further comprising heating atleast the portion of the formation to substantially pyrolyze at leastsome of the carbon within the formation.
 4077. An in situ method forheating a hydrocarbon containing formation, comprising: oxidizing a fuelfluid in a heater; providing at least a portion of the oxidized fuelfluid into a conduit disposed in an opening of the formation; allowingheat to transfer from the oxidized fuel fluid to a section of theformation; and allowing additional heat to transfer from an electricheater disposed in the opening to the section of the formation, whereinheat is allowed to transfer substantially uniformly along a length ofthe opening.
 4078. The method of claim 4077, wherein providing at leastthe portion of the oxidized fuel fluid into the opening comprisesflowing the oxidized fuel fluid through a perforated conduit disposed inthe opening.
 4079. The method of claim 4077, wherein providing at leastthe portion of the oxidized fuel fluid into the opening comprisesflowing the oxidized fuel fluid through a perforated conduit disposed inthe opening, the method further comprising removing an exhaust fluidthrough the opening.
 4080. The method of claim 4077, further comprisinginitiating oxidation of the fuel fluid in the heater with a flame. 4081.The method of claim 4077, further comprising removing the oxidized fuelfluid through the conduit.
 4082. The method of claim 4077, furthercomprising removing the oxidized fuel fluid through the conduit andproviding the removed oxidized fuel fluid to at least one additionalheater disposed in the formation.
 4083. The method of claim 4077,wherein the conduit comprises an insulator disposed on a surface of theconduit, the method further comprising tapering a thickness of theinsulator such that heat is allowed to transfer substantially uniformlyalong a length of the conduit.
 4084. The method of claim 4077, whereinthe electric heater is an insulated conductor.
 4085. The method of claim4077, wherein the electric heater is a conductor disposed in theconduit.
 4086. The method of claim 4077, wherein the electric heater isan elongated conductive member.
 4087. The method of claim 4077, whereinthe hydrocarbon containing formation comprises a coal containingformation.
 4088. The method of claim 4077, wherein the hydrocarboncontaining formation comprises an oil shale containing formation. 4089.The method of claim 4077, wherein the hydrocarbon containing formationcomprises a heavy oil and/or tar containing permeable formation. 4090.The method of claim 4077, wherein the hydrocarbon containing formationcomprises a heavy oil and/or tar containing impermeable formation. 4091.A system configured to heat a hydrocarbon containing formationcomprising: one or more heat sources disposed within one or more openwellbores in the formation, wherein the one or more heat sources areconfigured to provide heat to at least a portion of the formation duringuse; and wherein the system is configured to allow heat to transfer fromthe one or more heat sources to a selected section of the formationduring use.
 4092. The system of claim 4091, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 4093. Thesystem of claim 4091, wherein the one or more heat sources compriseelectrical heaters.
 4094. The system of claim 4091, wherein the one ormore heat sources comprise surface burners.
 4095. The system of claim4091, wherein the one or more heat sources comprise flamelessdistributed combustors.
 4096. The system of claim 4091, wherein the oneor more heat sources comprise natural distributed combustors.
 4097. Thesystem of claim 4091, wherein the one or more open wellbores comprise adiameter of at least approximately 5 cm.
 4098. The system of claim 4091,further comprising an overburden casing coupled to at least one of theone or more open wellbores, wherein the overburden casing is disposed inan overburden of the formation.
 4099. The system of claim 4091, furthercomprising an overburden casing coupled to at least one of the one ormore open wellbores, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing comprisessteel.
 4100. The system of claim 4091, further comprising an overburdencasing coupled to at least one of the one or more open wellbores,wherein the overburden casing is disposed in an overburden of theformation, and wherein the overburden casing is further disposed incement.
 4101. The system of claim 4091 further comprising an overburdencasing coupled to at least one of the one or more open wellbores,wherein the overburden casing is disposed in an overburden of theformation, and wherein a packing material is disposed at a junction ofthe overburden casing and the at least one of the one or more openwellbores.
 4102. The system of claim 4091, further comprising anoverburden casing coupled to at least one of the one or more openwellbores, wherein the overburden casing is disposed in an overburden ofthe formation, wherein a packing material is disposed at a junction ofthe overburden casing and the at least one of the one or more openwellbores, and wherein the packing material is configured tosubstantially inhibit a flow of fluid between at least one of the one ormore open wellbores and the overburden casing during use.
 4103. Thesystem of claim 4091, further comprising an overburden casing coupled toat least one of the one or more open wellbores, wherein the overburdencasing is disposed in an overburden of the formation, wherein a packingmaterial is disposed at a junction of the overburden casing and the atleast one of the one or more open wellbores, and wherein the packingmaterial comprises cement.
 4104. The system of claim 4091, wherein thesystem is further configured to transfer heat such that the transferredheat can pyrolyze at least some hydrocarbons in the selected section.4105. The system of claim 4091, further comprising a valve coupled to atleast one of the one or more heat sources configured to control pressurewithin at least a majority of the selected section of the formation.4106. The system of claim 4091, further comprising a valve coupled to aproduction well configured to control a pressure within at least amajority of the selected section of the formation.
 4107. A method oftreating a hydrocarbon containing formation in situ comprising:providing heat from one or more heat sources to at least one portion ofthe formation, wherein the one or more heat sources are disposed withinone or more open wellbores in the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation; and producing a mixture from the formation.
 4108. The methodof claim 4107, wherein the one or more heat sources comprise at leasttwo heat sources, and wherein superposition of heat from at least thetwo heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 4109. The method of claim 4107,wherein controlling formation conditions comprises maintaining atemperature within the selected section within a pyrolysis temperaturerange with a lower pyrolysis temperature of about 250° C., and an upperpyrolysis temperature of about 400° C.
 4110. The method of claim 4107,wherein the one or more heat sources comprise electrical heaters. 4111.The method of claim 4107, wherein the one or more heat sources comprisesurface burners.
 4112. The method of claim 4107, wherein the one or moreheat sources comprise flameless distributed combustors.
 4113. The methodof claim 4107, wherein the one or more heat sources comprise naturaldistributed combustors.
 4114. The method of claim 4107, wherein the oneor more heat sources are suspended within the one or more openwellbores.
 4115. The method of claim 4107, wherein a tube is disposed inat least one of the one or more open wellbores proximate to heat source,the method further comprising flowing a substantially constant amount afluid into at least one of the one or more open wellbores throughcritical flow orifices in the tube.
 4116. The method of claim 4107,wherein a perforated tube is disposed in at least one of the one or moreopen wellbores proximate to the heat source, the method furthercomprising flowing a corrosion inhibiting fluid into at least one of theopen wellbores through the perforated tube.
 4117. The method of claim4107, further comprising coupling an overburden casing to at least oneof the one or more open wellbores, wherein the overburden casing isdisposed in an overburden of the formation.
 4118. The method of claim4107, further comprising coupling an overburden casing to at least oneof the one or more open wellbores, wherein the overburden casing isdisposed in an overburden of the formation, and wherein the overburdencasing comprise steel.
 4119. The method of claim 4107, furthercomprising coupling an overburden casing to at least one of the one ormore open wellbores, wherein the overburden casing is disposed in anoverburden of the formation, and wherein the overburden casing isfurther disposed in cement.
 4120. The method of claim 4107, furthercomprising coupling an overburden casing to at least one of the one ormore open wellbores, wherein the overburden casing is disposed in anoverburden of the formation, and wherein a packing material is disposedat a junction of the overburden casing and the at least one of the oneor more open wellbores.
 4121. The method of claim 4107, furthercomprising coupling an overburden casing to at least one of the one ormore open wellbores wherein the overburden casing is disposed in anoverburden of the formation, and wherein the method further comprisesinhibiting a flow of fluid between the at least one of the one or moreopen wellbores and the overburden casing with a packing material. 4122.The method of claim 4107, further comprising heating at least theportion of the formation to substantially pyrolyze at least some of thecarbon within the formation. 4123 . The method of claim 4107, furthercomprising controlling a pressure and a temperature within at least amajority of the selected section of the formation, wherein the pressureis controlled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 4124. The method of claim 4107,further comprising controlling a pressure with the wellbore.
 4125. Themethod of claim 4107, further comprising controlling a pressure withinat least a majority of the selected section of the formation with avalve coupled to at least one of the one or more heat sources.
 4126. Themethod of claim 4107, further comprising controlling a pressure withinat least a majority of the selected section of the formation with avalve coupled to a production well located in the formation.
 4127. Themethod of claim 4107, further comprising controlling the heat such thatan average heating rate of the selected section is less than about 1° C.per day during pyrolysis.
 4128. The method of claim 4107, whereinproviding heat from the one or more heat sources to at least the portionof formation comprises: heating a selected volume (V) of the hydrocarboncontaining formation from the one or more heat sources, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 4129. Themethod of claim 4107, wherein allowing the heat to transfer from the oneor more heat sources to the selected section comprises transferring heatsubstantially by conduction.
 4130. The method of claim 4107, whereinproviding heat from the one or more heat sources comprises heating theselected section such that a thermal conductivity of at least a portionof the selected section is greater than about 0.5 W/(m ° C.).
 4131. Themethod of claim 4107, wherein the produced mixture comprises condensablehydrocarbons having an API gravity of at least about 25°.
 4132. Themethod of claim 4107, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 0.1% by weight to about 15% by weight ofthe condensable hydrocarbons are olefins.
 4133. The method of claim4107, wherein the produced mixture comprises non-condensablehydrocarbons, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.4134. The method of claim 4107, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein about 0.1% by weight to about15% by weight of the non-condensable hydrocarbons are olefins.
 4135. Themethod of claim 4107 wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 1% by weight, when calculatedon an atomic basis, of the condensable hydrocarbons is nitrogen. 4136.The method of claim 4107, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 4137. The method of claim 4107, wherein the produced mixturecomprises condensable hydrocarbons, wherein about 5% by weight to about30% by weight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.4138. The method of claim 4107, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 4139. The method of claim 4107, wherein the produced mixturecomprises condensable hydrocarbons, and wherein greater than about 20%by weight of the condensable hydrocarbons are aromatic compounds. 4140.The method of claim 4107, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 5% by weight ofthe condensable hydrocarbons comprises multi-ring aromatics with morethan two rings.
 4141. The method of claim 4107, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4142.The method of claim 4107, wherein the produced mixture comprisescondensable hydrocarbons, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4143. Themethod of claim 4107, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable componentcomprises hydrogen and wherein the hydrogen is greater than about 10% byvolume of the non-condensable component and wherein the hydrogen is lessthan about 80% by volume of the non-condensable component.
 4144. Themethod of claim 4107, wherein the produced mixture comprises ammonia,and wherein greater than about 0.05% by weight of the produced mixtureis ammonia.
 4145. The method of claim 4107, wherein the produced mixturecomprises ammonia, and wherein the ammonia is used to producefertilizer.
 4146. The method of claim 4107, further comprisingcontrolling a pressure within at least a majority of the selectedsection of the formation.
 4147. The method of claim 4107, furthercomprising controlling a pressure within at least a majority of theselected section of the formation, wherein the controlled pressure is atleast about 2.0 bar absolute.
 4148. The method of claim 4107, furthercomprising controlling formation conditions such that the producedmixture comprises a partial pressure of H₂ within the mixture greaterthan about 0.5 bar.
 4149. The method of claim 4148, wherein the partialpressure of H₂ is measured when the mixture is at a production well.4150. The method of claim 4107, wherein controlling formation conditionscomprises recirculating a portion of hydrogen from the mixture into theformation.
 4151. The method of claim 4107, further comprising altering apressure within the formation to inhibit production of hydrocarbons fromthe formation having carbon numbers greater than about
 25. 4152. Themethod of claim 4107, further comprising: providing hydrogen (H₂) to theheated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 4153. Themethod of claim 4107, wherein the produced mixture comprises hydrogenand condensable hydrocarbons, the method further comprisinghydrogenating a portion of the produced condensable hydrocarbons with atleast a portion of the produced hydrogen.
 4154. The method of claim4107, wherein allowing the heat to transfer comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 4155. The method of claim 4107, wherein allowing theheat to transfer comprises substantially uniformly increasing apermeability of a majority of the selected section.
 4156. The method ofclaim 4107, further comprising controlling the heat to yield greaterthan about 60% by weight of condensable hydrocarbons, as measured by theFischer Assay.
 4157. The method of claim 4107, wherein producing themixture comprises producing the mixture in a production well, andwherein at least about 7 heat sources are disposed in the formation forthe production well.
 4158. The method of claim 4107, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 4159. The method of claim 4107,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 4160. The method of claim 4107,further comprising separating the produced mixture into a gas stream anda liquid stream.
 4161. The method of claim 4107, further comprisingseparating the produced mixture into a gas stream and a liquid streamand separating the liquid stream into an aqueous stream and anon-aqueous stream.
 4162. The method of claim 4107, wherein the producedmixture comprises H₂S, the method further comprising separating aportion of the H₂S from non-condensable hydrocarbons.
 4163. The methodof claim 4107, wherein the produced mixture comprises CO₂, the methodfurther comprising separating a portion of the CO₂ from non-condensablehydrocarbons.
 4164. The method of claim 4107, wherein the mixture isproduced from a production well, wherein the heating is controlled suchthat the mixture can be produced from the formation as a vapor. 4165.The method of claim 4107, wherein the mixture is produced from aproduction well, the method further comprising heating a wellbore of theproduction well to inhibit condensation of the mixture within thewellbore.
 4166. The method of claim 4107, wherein the mixture isproduced from a production well, wherein a wellbore of the productionwell comprises a heater element configured to beat the formationadjacent to the wellbore, and further comprising heating the formationwith the heater element to produce the mixture, wherein the mixturecomprises a large non-condensable hydrocarbon gas component and H₂.4167. The method of claim 4107, wherein the selected section is heatedto a minimum pyrolysis temperature of about 270° C.
 4168. The method ofclaim 4107, further comprising maintaining the pressure within theformation above about 2.0 bar absolute to inhibit production of fluidshaving carbon numbers above
 25. 4169. The method of claim 4107, furthercomprising controlling pressure within the formation in a range fromabout atmospheric pressure to about 100 bar, as measured at a wellheadof a production well, to control an amount of condensable hydrocarbonswithin the produced mixture, wherein the pressure is reduced to increaseproduction of condensable hydrocarbons, and wherein the pressure isincreased to increase production of non-condensable hydrocarbons. 4170.The method of claim 4107, further comprising controlling pressure withinthe formation in a range from about atmospheric pressure to about 100bar, as measured at a wellhead of a production well, to control an APIgravity of condensable hydrocarbons within the produced mixture, whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 4171. A mixtureproduced from a portion of a hydrocarbon containing formation, themixture comprising: an olefin content of less than about 10% by weight;and an average carbon number less than about
 35. 4172. The mixture ofclaim 4171, further comprising an average carbon number less than about30.
 4173. The mixture of claim 4171, further comprising an averagecarbon number less than about
 25. 4174. The mixture of claim 4171,further comprising: non-condensable hydrocarbons comprising hydrocarbonshaving carbon numbers of less than 5; and wherein a weight ratio of thehydrocarbons having carbon numbers from 2 through 4, to methane, in themixture is greater than approximately
 1. 4175. The mixture of claim4171, further comprising condensable hydrocarbons, wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen, wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons issulfur.
 4176. The mixture of claim 4171, further comprising ammonia,wherein greater than about 0.05% by weight of the produced mixture isammonia.
 4177. The mixture of claim 4171, further comprising condensablehydrocarbons, wherein an olefin content of the condensable hydrocarbonsis greater than about 0.1% by weight of the condensable hydrocarbons,and wherein the olefin content of the condensable hydrocarbons is lessthan about 15% by weight of the condensable hydrocarbons.
 4178. Themixture of claim 4171, further comprising condensable hydrocarbons,wherein less than about 15% by weight of the condensable hydrocarbonshave a carbon number greater than about
 25. 4179. The condensablehydrocarbons of claim 4178, wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen, wherein less than about 1% by weight, when calculated on anatomic basis, of the condensable hydrocarbons is oxygen, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 4180. The mixture of claim 4177,further comprising condensable hydrocarbons, wherein greater than about20% by weight of the condensable hydrocarbons are aromatic compounds.4181. The mixture of claim 4171, further comprising: non-condensablehydrocarbons comprising hydrocarbons having carbon numbers of less thanabout 5, wherein a weight ratio of the hydrocarbons having carbon numberfrom 2 through 4, to methane, in the mixture is greater thanapproximately 1; wherein the non-condensable hydrocarbons furthercomprise H₂, wherein greater than about 15% by weight of thenon-condensable hydrocarbons comprises H₂; and condensable hydrocarbons,comprising: oxygenated hydrocarbons, wherein greater than about 1.5% byweight of the condensable hydrocarbons comprises oxygenatedhydrocarbons; and aromatic compounds, wherein greater than about 20% byweight of the condensable hydrocarbons comprises aromatic compounds.4182. The mixture of claim 4171, further comprising: condensablehydrocarbons, wherein less than about 5% by weight of the condensablehydrocarbons comprises hydrocarbons having a carbon number greater thanabout 25; wherein the condensable hydrocarbons further comprise:oxygenated hydrocarbons, wherein greater than about 5% by weight of thecondensable hydrocarbons comprises oxygenated hydrocarbons; and aromaticcompounds, wherein greater than about 30% by weight of the condensablehydrocarbons comprises aromatic compounds; and non-condensablehydrocarbons comprising H₂, wherein greater than about 15% by weight ofthe non-condensable hydrocarbons comprises H₂.
 4183. The mixture ofclaim 4171, further comprising a condensable mixture, comprising:olefins, wherein about 0.1% by weight to about 15% by weight of thecondensable mixture comprises olefins; and asphaltenes, wherein lessthan about 0.1% by weight of the condensable mixture comprisesasphaltenes.
 4184. The condensable mixture of claim 4183, furthercomprising, oxygenated hydrocarbons, wherein less than about 15% byweight of the condensable mixture comprises oxygenated hydrocarbons;4185. The mixture of claim 4171, further comprising a condensablemixture, comprising: olefins, wherein about 0.1% by weight to about 2%by weight of the condensable mixture comprises olefins; and multi-ringaromatics, wherein less than about 2% by weight of the condensablemixture comprises multi-ring aromatics with more than two rings. 4186.The condensable mixture of claim 4184, further comprising oxygenatedhydrocarbons, wherein greater than about 25% by weight of thecondensable mixture comprises oxygenated hydrocarbons.
 4187. The mixtureof claim 4171, further comprising: non-condensable hydrocarbons, whereinthe non-condensable hydrocarbons comprise H₂, wherein greater than about10% by weight of the non-condensable hydrocarbons comprises H₂; ammonia,wherein greater than about 0.5% by weight of the mixture comprisesammonia; and hydrocarbons, wherein a weight ratio of hydrocarbons havinggreater than about 2 carbon atoms, to methane, is greater than about0.4.
 4188. A mixture produced from a portion of a hydrocarbon containingformation, the mixture, comprising: non-condensable hydrocarbonscomprising hydrocarbons having carbon numbers of less than 5; andwherein a weight ratio of the hydrocarbons having carbon numbers from 2through 4, to methane, in the mixture is greater than approximately 1.4189. The mixture of claim 4175, further comprising condensablehydrocarbons, wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 4190. The mixture of claim 4175,wherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 4191. The mixture ofclaim 4175, further comprising condensable hydrocarbons, wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is nitrogen.
 4192. The mixture of claim 4175,further comprising condensable hydrocarbons, wherein less than about 1%by weight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 4193. The mixture of claim 4175, furthercomprising condensable hydrocarbons, wherein about 5% by weight to about30% by weight of the condensable hydrocarbons comprise oxygen containingcompounds, and wherein the oxygen containing compounds comprise phenols.4194. The mixture of claim 4175, further comprising condensablehydrocarbons, wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is sulfur.
 4195. Themixture of claim 4175, further comprising condensable hydrocarbons,wherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 4196. The mixture of claim 4175, furthercomprising condensable hydrocarbons, wherein less than about 5% byweight of the condensable hydrocarbons comprises multi-ring aromaticswith more than two rings.
 4197. The mixture of claim 4175, furthercomprising condensable hydrocarbons, wherein less than about 0.3% byweight of the condensable hydrocarbons are asphaltenes.
 4198. Themixture of claim 4175, further comprising condensable hydrocarbons,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise cycloalkanes.
 4199. The mixture of claim 4175,wherein the non-condensable hydrocarbons further comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable hydrocarbons, and wherein the hydrogen is less thanabout 80% by volume of the non-condensable hydrocarbons.
 4200. Themixture of claim 4175, further comprising ammonia, wherein greater thanabout 0.05% by weight of the produced mixture is ammonia.
 4201. Themixture of claim 4175, further comprising ammonia, wherein the ammoniais used to produce fertilizer.
 4202. The mixture of claim 4175, furthercomprising condensable hydrocarbons, wherein less than about 15 weight %of the condensable hydrocarbons have a carbon number greater thanapproximately
 25. 4203. The mixture of claim 4175, further comprisingcondensable hydrocarbons, wherein the condensable hydrocarbons compriseolefins, and wherein about 0.1% to about 5% by weight of the condensablehydrocarbons comprises olefins.
 4204. The mixture of claim 4175, furthercomprising condensable hydrocarbons, wherein the condensablehydrocarbons comprises olefins, and wherein about 0.1% to about 2.5% byweight of the condensable hydrocarbons comprises olefins.
 4205. Themixture of claim 4175, further comprising condensable hydrocarbons,wherein the condensable hydrocarbons comprise oxygenated hydrocarbons,and wherein greater than about 5% by weight of the condensablehydrocarbons comprises oxygenated hydrocarbons.
 4206. The mixture ofclaim 4175, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise H₂, and wherein greater than about5% by weight of the non-condensable hydrocarbons comprises H₂.
 4207. Themixture of claim 4175, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprise H₂, and whereingreater than about 15% by weight of the non-condensable hydrocarbonscomprises H₂.
 4208. The mixture of claim 4175, wherein a weight ratio ofhydrocarbons having greater than about 2 carbon atoms, to methane, isgreater than about 0.3.
 4209. A mixture produced from a portion of ahydrocarbon containing formation, the mixture comprising:non-condensable hydrocarbons comprising hydrocarbons having carbonnumbers of less than 5, wherein a weight ratio of hydrocarbons havingcarbon numbers from 2 through 4, to methane, is greater thanapproximately 1; and condensable hydrocarbons comprising oxygenatedhydrocarbons, wherein greater than about 5% by weight of the condensablecomponent comprises oxygenated hydrocarbons.
 4210. The mixture of claim4209, wherein about 0.1% by weight to about 15% by weight of thecondensable hydrocarbons are olefins.
 4211. The mixture of claim 4209,wherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 4212. The mixture ofclaim 4209, wherein less than about 1% by weight, when calculated on anatomic basis, of the condensable hydrocarbons is nitrogen.
 4213. Themixture of claim 4209, wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 4214. The mixture of claim 4209, wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4215. The mixture of claim 4209, wherein about5% by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 4216. The mixture of claim 4209, whereingreater than about 20% by weight of the condensable hydrocarbons arearomatic compounds.
 4217. The mixture of claim 4209, wherein less thanabout 5% by weight of the condensable hydrocarbons comprises multi-ringaromatics with more than two rings.
 4218. The mixture of claim 4209,wherein less than about 0.3% by weight of the condensable hydrocarbonsare asphaltenes.
 4219. The mixture of claim 4209, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons arecycloalkanes.
 4220. The mixture of claim 4209, wherein thenon-condensable hydrocarbons comprises hydrogen, wherein the hydrogen isgreater than about 10% by volume of the non-condensable hydrocarbons,and wherein the hydrogen is less than about 80% by volume of thenon-condensable hydrocarbons.
 4221. The mixture of claim 4209, whereinthe produced mixture comprises ammonia, and wherein greater than about0.05% by weight of the produced mixture is ammonia.
 4222. The mixture ofclaim 4209, wherein the produced mixture comprises ammonia, and whereinthe ammonia is used to produce fertilizer.
 4223. The mixture of claim4209, wherein less than about 5 weight % of the condensable hydrocarbonsin the mixture have a carbon number greater than approximately
 25. 4224.The mixture of claim 4209, wherein the condensable hydrocarbons furthercomprise olefins, and wherein about 0.1% to about 5% by weight of thecondensable hydrocarbons comprises olefins.
 4225. The mixture of claim4209, wherein the condensable hydrocarbons further comprise olefins, andwherein about 0.1% to about 2.5% by weight of the condensablehydrocarbons comprises olefins.
 4226. The mixture of claim 4209, whereinthe non-condensable hydrocarbons further comprise H₂, wherein greaterthan about 5% by weight of the mixture comprises H₂.
 4227. The mixtureof claim 4209, wherein the non-condensable hydrocarbons further compriseH₂, wherein greater than about 15% by weight of the mixture comprisesH₂.
 4228. The mixture of claim 4209, wherein a weight ratio ofhydrocarbons having greater than about 2 carbon atoms, to me thane, isgreater than about 0.3.
 4229. A mixture produced from a portion of ahydrocarbon containing formation the mixture comprising: non-condensablehydrocarbons comprising hydrocarbons having carbon numbers of less than5, wherein a weight ratio of hydrocarbons having carbon numbers from 2through 4, to methane, is greater than approximately 1; condensablehydrocarbons; wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons comprises nitrogen;wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons comprises oxygen; and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons comprises sulfur.
 4230. The mixture of claim4229, further comprising ammonia, wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 4231. The mixture of claim4229, wherein less than about 5 weight % of the condensable hydrocarbonshave a carbon number greater than approximately
 25. 4232. The mixture ofclaim 4229, wherein the condensable hydrocarbons comprise olefins, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 4233. The mixture of claim 4229, wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 4234. The mixture of claim 4229,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4235. The mixture of claim4229, wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 4236. The mixture of claim 4229,wherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4237. Themixture of claim 4229, wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4238. The mixture of claim4229, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons are cycloalkanes.
 4239. The mixture of claim4229, wherein the non-condensable hydrocarbons comprises hydrogen, andwherein the hydrogen is greater than about 10% by volume of thenon-condensable hydrocarbons and wherein the hydrogen is less than about80% by volume of the non-condensable hydrocarbons.
 4240. The mixture ofclaim 4229, further comprising ammonia, and wherein greater than about0.05% by weight of the produced mixture is ammonia.
 4241. The mixture ofclaim 4229, further comprising ammonia, and wherein the ammonia is usedto produce fertilizer.
 4242. The mixture of claim 4229, wherein thecondensable hydrocarbons comprises oxygenated hydrocarbons, and whereingreater than about 5% by weight of the condensable component comprisesoxygenated hydrocarbons.
 4243. The mixture of claim 4229, wherein thenon-condensable hydrocarbons comprise H₂, and wherein greater than about5% by weight of the non-condensable hydrocarbons comprises H₂.
 4244. Themixture of claim 4229, wherein the non-condensable hydrocarbons compriseH₂, and wherein greater than about 15% by weight of the mixturecomprises H₂.
 4245. The mixture of claim 4229, wherein a weight ratio ofhydrocarbons having greater than about 2 carbon atoms, to methane, isgreater, than about 0.3.
 4246. A mixture produced from a portion of ahydrocarbon containing formation, the mixture comprising:non-condensable hydrocarbons comprising hydrocarbons having carbonnumbers of less than 5, wherein a weight ratio of hydrocarbons havingcarbon numbers from 2 through 4, to methane, is greater thanapproximately 1; ammonia, wherein greater than about 0.5% by weight ofthe mixture comprises ammonia; and condensable hydrocarbons comprisingoxygenated hydrocarbons, wherein greater than about 5% by weight of thecondensable hydrocarbons comprises oxygenated hydrocarbons.
 4247. Themixture of claim 4246, wherein the condensable hydrocarbons furthercomprise olefins, and wherein about 0.1% by weight to about 15% byweight of the condensable hydrocarbons are olefins.
 4248. The mixture ofclaim 4246, wherein the non-condensable hydrocarbons further compriseethene and ethane, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.4249. The mixture of claim 4246, wherein the condensable hydrocarbonsfurther comprise nitrogen, and wherein less than about 1% by weight,when calculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4250. The mixture of claim 4246, wherein the condensablehydrocarbons further comprise oxygen, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 4251. The mixture of claim 4246, wherein thecondensable hydrocarbons further comprise sulfur, and wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 4252. The mixture of claim 4246,wherein the condensable hydrocarbons further comprise oxygen containingcompounds, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 4253. Themixture of claim 4246, wherein the condensable hydrocarbons furthercomprise aromatic compounds, and wherein greater than about 20% byweight of the condensable hydrocarbons are aromatic compounds.
 4254. Themixture of claim 4246, wherein the condensable hydrocarbons furthercomprise multi-aromatic rings, and wherein less than about 5% by weightof the condensable hydrocarbons comprises multi-ring aromatics with morethan two rings.
 4255. The mixture of claim 4246, wherein the condensablehydrocarbons further comprise asphaltenes, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4256.The mixture of claim 4246, wherein the condensable hydrocarbons furthercomprise cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4257. Themixture of claim 4246, wherein the non-condensable hydrocarbons furthercomprise hydrogen, wherein the hydrogen is greater than about 10% byvolume of the non-condensable hydrocarbons, and wherein the hydrogen isless than about 80% by volume of the non-condensable hydrocarbons. 4258.The mixture of claim 4246, wherein the produced mixture furthercomprises ammonia, and wherein greater than about 0.05% by weight of theproduced mixture is ammonia.
 4259. The mixture of claim 4246, whereinthe produced mixture further comprises ammonia, and wherein the ammoniais used to produce fertilizer.
 4260. The mixture of claim 4246, whereinthe condensable hydrocarbons comprise hydrocarbons having a carbonnumber of greater than approximately 25, and wherein less than about 15weight % of the hydrocarbons in the mixture have a carbon number greaterthan approximately
 25. 4261. The mixture of claim 4246, wherein thenon-condensable hydrocarbons further comprise H₂, and wherein greaterthan about 5% by weight of the mixture comprises H₂.
 4262. The mixtureof claim 4246, wherein the non-condensable hydrocarbons further compriseH₂, and wherein greater than about 15% by weight of the mixturecomprises H₂.
 4263. The mixture of claim 4246, wherein thenon-condensable hydrocarbons further comprise hydrocarbons having carbonnumbers of greater than 2, wherein a weight ratio of hydrocarbons havingcarbon numbers greater than 2, to methane, is greater than about 0.34264. A mixture produced from a portion of a hydrocarbon containingformation, the mixture comprising: non-condensable hydrocarbonscomprising hydrocarbons having carbon numbers of less than 5, wherein aweight ratio of hydrocarbons having carbon numbers from 2 through 4, tomethane, is greater than approximately 1; and condensable hydrocarbonscomprising olefins, wherein less than about 10% by weight of thecondensable hydrocarbons comprises olefins.
 4265. The mixture of claim4264, wherein the non-condensable hydrocarbons farther comprise etheneand ethane, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.4266. The mixture of claim 4264, wherein the condensable hydrocarbonsfurther comprise nitrogen, and wherein less than about 1% by weight,when calculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4267. The mixture of claim 4264, wherein the condensablehydrocarbons further comprise oxygen, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 4268. The mixture of claim 4264, wherein thecondensable hydrocarbons further comprise sulfur, and wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 4269. The mixture of claim 4264,wherein the condensable hydrocarbons further comprise oxygen containingcompounds, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 4270. Themixture of claim 4264, wherein the condensable hydrocarbons furthercomprise aromatic compounds, and wherein greater than about 20% byweight of the condensable hydrocarbons are aromatic compounds.
 4271. Themixture of claim 4264, wherein the condensable hydrocarbons furthercomprise multi-ring aromatics, and wherein less than about 5% by weightof the condensable hydrocarbons comprises multi-ring aromatics with morethan two rings.
 4272. The mixture of claim 4264, wherein the condensablehydrocarbons further comprise asphaltenes, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4273.The mixture of claim 4264, wherein the condensable hydrocarbons furthercomprise cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4274. Themixture of claim 4264, wherein the non-condensable hydrocarbons furthercomprise hydrogen, and wherein the hydrogen is greater than about 10% byvolume of the non-condensable hydrocarbons and wherein the hydrogen isless than about 80% by volume of the non-condensable hydrocarbons. 4275.The mixture of claim 4264, wherein the produced mixture furthercomprises ammonia, and wherein greater than about 0.05% by weight of theproduced mixture is ammonia.
 4276. The mixture of claim 4264, whereinthe produced mixture further comprises ammonia, and wherein the ammoniais used to produce fertilizer.
 4277. The mixture of claim 4264, whereinthe condensable hydrocarbons further comprise hydrocarbons having acarbon number of greater than approximately 25, and wherein less thanabout 15% by weight of the hydrocarbons have a carbon number greaterthan approximately
 25. 4278. The mixture of claim 4264, wherein about0.1% to about 5% by weight of the condensable component comprisesolefins.
 4279. The mixture of claim 4264, wherein about 0.1% to about 2%by weight of the condensable component comprises olefins.
 4280. Themixture of claim 4264, wherein the condensable hydrocarbons furthercomprise oxygenated hydrocarbons, and wherein greater than about 5% byweight of the condensable hydrocarbons comprises oxygenatedhydrocarbons.
 4281. The mixture of claim 4264, wherein the condensablehydrocarbons further comprise oxygenated hydrocarbons, and whereingreater than about 25% by weight of the condensable component comprisesoxygenated hydrocarbons.
 4282. The mixture of claim 4264, wherein thenon-condensable hydrocarbons further comprise H₂, and wherein greaterthan about 5% by weight of the non-condensable hydrocarbons comprisesH₂.
 4283. The mixture of claim 4264, wherein the non-condensablehydrocarbons further comprise H₂, and wherein greater than about 15% byweight of the non-condensable hydrocarbons comprises H₂.
 4284. Themixture of claim 4264, wherein a weight ratio of hydrocarbons havinggreater than about 2 carbon atoms, to methane, is greater than about0.3.
 4285. A mixture produced from a portion of a hydrocarbon containingformation, comprising: condensable hydrocarbons, wherein less than about15 weight % of the condensable hydrocarbons have a carbon number greaterthan 25; and wherein the condensable hydrocarbons comprise oxygenatedhydrocarbons, and wherein greater than about 5% by weight of thecondensable hydrocarbons comprises oxygenated hydrocarbons.
 4286. Themixture of claim 4285, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprise hydrocarbons havingcarbon numbers of less than 5, and wherein a weight ratio ofhydrocarbons having carbon numbers from 2 through 4, to methane, isgreater than approximately
 1. 4287. The mixture of claim 4285, whereinthe condensable hydrocarbons further comprise olefins, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 4288. The mixture of claim 4285, further comprisingnon-condensable hydrocarbons, wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons ranges from about 0.001 to about0.15.
 4289. The mixture of claim 4285, wherein the condensablehydrocarbons further comprise nitrogen, and wherein less than about 1%by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 4290. The mixture of claim 4285, wherein thecondensable hydrocarbons further comprise oxygen, and wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4291. The mixture of claim 4285,wherein the condensable hydrocarbons further comprise sulfur, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 4292. The mixture ofclaim 4285, wherein the condensable hydrocarbons further comprise oxygencontaining compounds, wherein about 5% by weight to about 30% by weightof the condensable hydrocarbons comprise oxygen containing compounds,and wherein the oxygen containing compounds comprise phenols.
 4293. Themixture of claim 4285, wherein the condensable hydrocarbons furthercomprise aromatic compounds, and wherein greater than about 20% byweight of the condensable hydrocarbons are aromatic compounds.
 4294. Themixture of claim 4285, wherein the condensable hydrocarbons furthercomprise multi-ring aromatics, and wherein less than about 5% by weightof the condensable hydrocarbons comprises multi-ring aromatics with morethan two rings.
 4295. The mixture of claim 4285, wherein the condensablehydrocarbons further comprise asphaltenes, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4296.The mixture of claim 4285, wherein the condensable hydrocarbons furthercomprise cycloalkanes, and wherein about 5% by weight to about 30% byweight of the condensable hydrocarbons are cycloalkanes.
 4297. Themixture of claim 4285, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprise hydrogen, and whereinthe hydrogen is greater than about 10% by volume of the non-condensablehydrocarbons and wherein the hydrogen is less than about 80% by volumeof the non-condensable hydrocarbons.
 4298. The mixture of claim 4285,further comprising ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 4299. The mixture of claim4285, further comprising ammonia, and wherein the ammonia is used toproduce fertilizer.
 4300. The mixture of claim 4285, wherein thecondensable hydrocarbons further comprises olefins, and wherein lessthan about 10% by weight of the condensable hydrocarbons comprisesolefins.
 4301. The mixture of claim 4285, wherein the condensablehydrocarbons further comprises olefins, and wherein about 0.1% to about5% by weight of the condensable hydrocarbons comprises olefins. 4302.The mixture of claim 4285, wherein the condensable hydrocarbons furthercomprises olefins, and wherein about 0.1% to about 2% by weight of thecondensable hydrocarbons comprises olefins.
 4303. The mixture of claim4285, wherein the condensable hydrocarbons further comprises oxygenatedhydrocarbons, and wherein greater than about 5% by weight of thecondensable hydrocarbons comprises the oxygenated hydrocarbon.
 4304. Themixture of claim 4285, further comprising non-condensable hydrocarbons,wherein the non-condensable hydrocarbons comprise H₂, wherein greaterthan about 5% by weight of the non-condensable hydrocarbons comprisesH₂.
 4305. The mixture of claim 4285, further comprising non-condensablehydrocarbons, wherein the non-condensable hydrocarbons comprise H₂,wherein greater than about 15 % by weight of the non-condensablehydrocarbons comprises H₂.
 4306. The mixture of claim 4285, wherein aweight ratio of hydrocarbons having greater than about 2 carbon atoms,to methane, is greater than about 0.3.
 4307. A mixture produced from aportion of a hydrocarbon containing formation, comprising: condensablehydrocarbons, wherein less than about 15% by weight of the condensablehydrocarbons have a carbon number greater than about 25; wherein lessthan about 1% by weight of the condensable hydrocarbons, when calculatedon an atomic basis, is nitrogen; wherein less than about 1% by weight ofthe condensable hydrocarbons, when calculated on an atomic basis, isoxygen; and wherein less than about 1% by weight of the condensablehydrocarbons, when calculated on an atomic basis, is sulfur.
 4308. Themixture of claim 4307, further comprising non-condensable hydrocarbons,wherein the non-condensable component comprises hydrocarbons havingcarbon numbers of less than 5, and wherein a weight ratio ofhydrocarbons having carbon numbers from 2 through 4, to methane, isgreater than approximately
 1. 4309. The mixture of claim 4307, whereinthe condensable hydrocarbons further comprise olefins, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 4310. The mixture of claim 4307, further comprisingnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 4311. The mixture of claim 4307, wherein the condensablehydrocarbons further comprise oxygen containing compounds, wherein about5% by weight to about 30% by weight of the condensable hydrocarbonscomprise oxygen containing compounds, and wherein the oxygen containingcompounds comprise phenols.
 4312. The mixture of claim 4307, wherein thecondensable hydrocarbons further comprise aromatic compounds, andwherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 4313. The mixture of claim 4307, wherein thecondensable hydrocarbons further comprise multi-ring aromatics, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4314. Themixture of claim 4307, wherein the condensable hydrocarbons furthercomprise asphaltenes, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4315. The mixture of claim4307, wherein the condensable hydrocarbons further comprisecycloalkanes, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4316. The mixture ofclaim 4307, further comprising non-condensable hydrocarbons, and whereinthe non-condensable hydrocarbons comprise hydrogen, and wherein greaterthan about 10% by volume and less than about 80% by volume of thenon-condensable component comprises hydrogen.
 4317. The mixture of claim4307, further comprising ammonia, and wherein greater than about 0.05%by weight of the produced mixture is ammonia.
 4318. The mixture of claim4307, further comprising ammonia, and wherein the ammonia is used toproduce fertilizer.
 4319. The mixture of claim 4307, wherein thecondensable component further comprises olefins, and wherein about 0.1%to about 5% by weight of the condensable component comprises olefins.4320. The mixture of claim 4307, wherein the condensable componentfurther comprises olefins, and wherein about 0.1% to about 2.5% byweight of the condensable component comprises olefins.
 4321. The mixtureof claim 4307, wherein the condensable hydrocarbons further compriseoxygenated hydrocarbons, and wherein greater than about 5% by weight ofthe condensable hydrocarbons comprises oxygenated hydrocarbons. 4322.The mixture of claim 4307, further comprising non-condensablehydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, andwherein greater than about 5% by weight of the non-condensablehydrocarbons comprises H₂.
 4323. The mixture of claim 4307, furthercomprising non-condensable hydrocarbons, wherein the non-condensablehydrocarbons comprise H₂, and wherein greater than about 15% by weightof the non-condensable hydrocarbons comprises H₂.
 4324. The mixture ofclaim 4307, further comprising non-condensable hydrocarbons, wherein aweight ratio of compounds within the non-condensable hydrocarbons havinggreater than about 2 carbon atoms, to methane, is greater than about0.3.
 4325. A mixture produced from a portion of a hydrocarbon containingformation, comprising: condensable hydrocarbons, wherein less than about15% by weight of the condensable hydrocarbons have a carbon numbergreater than 20; and wherein the condensable hydrocarbons compriseolefins, wherein an olefin content of the condensable component is lessthan about 10% by weight of the condensable component.
 4326. The mixtureof claim 4325, further comprising non-condensable hydrocarbons, whereinthe non-condensable hydrocarbons comprise hydrocarbons having carbonnumbers of less than 5, and wherein a weight ratio of hydrocarbonshaving carbon numbers from 2 through 4, to methane, is greater thanapproximately
 1. 4327. The mixture of claim 4325, wherein thecondensable hydrocarbons further comprise olefins, and wherein about0.1% by weight to about 15% by weight of the condensable hydrocarbonsare olefins.
 4328. The mixture of claim 4325, further comprisingnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 4329. The mixture of claim 4325, wherein the condensablehydrocarbons further comprise nitrogen, and wherein less than about 1%by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 4330. The mixture of claim 4325, wherein thecondensable hydrocarbons further comprise oxygen, and wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4331. The mixture of claim 4325,wherein the condensable hydrocarbons further comprise sulfur, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 4332. The mixture ofclaim 4325, wherein the condensable hydrocarbons, wherein about 5% byweight to about 30% by weight of the condensable hydrocarbons compriseoxygen containing compounds, and wherein the oxygen containing compoundscomprise phenols.
 4333. The mixture of claim 4325, wherein thecondensable hydrocarbons further comprise aromatic compounds, andwherein greater than about 20% by weight of the condensable hydrocarbonsare aromatic compounds.
 4334. The mixture of claim 4325, wherein thecondensable hydrocarbons further comprise multi-ring aromatics, andwherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4335. Themixture of claim 4325, wherein the condensable hydrocarbons furthercomprise asphaltenes, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4336. The mixture of claim4325, wherein the condensable hydrocarbons further comprisecycloalkanes, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4337. The mixture ofclaim 4325, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprises hydrogen, and wherein thehydrogen is about 10% by volume to about 80% by volume of thenon-condensable hydrocarbons.
 4338. The mixture of claim 4325, furthercomprising ammonia, wherein greater than about 0.05% by weight of theproduced mixture is ammonia.
 4339. The mixture of claim 4325, furthercomprising ammonia, and wherein the ammonia is used to producefertilizer.
 4340. The mixture of claim 4325, wherein about 0.1% to about5% by weight of the condensable component comprises olefins.
 4341. Themixture of claim 4325, wherein about 0.1% to about 2% by weight of thecondensable component comprises olefins.
 4342. The mixture of claim4325, wherein the condensable component further comprises oxygenatedhydrocarbons, and wherein greater than about 1.5% by weight of thecondensable component comprises oxygenated hydrocarbons.
 4343. Themixture of claim 4325, wherein the condensable component furthercomprises oxygenated hydrocarbons, and wherein greater than about 25% byweight of the condensable component comprises oxygenated hydrocarbons.4344. The mixture of claim 4325, further comprising non-condensablehydrocarbons, wherein the non-condensable hydrocarbons comprise H₂, andwherein greater than about 5% by weight of the non-condensablehydrocarbons comprises H₂.
 4345. The mixture of claim 4325, furthercomprising non-condensable hydrocarbons, wherein the non-condensablehydrocarbons comprise H₂, and wherein greater than about 15% by weightof the non-condensable hydrocarbons comprises H₂.
 4346. The mixture ofclaim 4325, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise hydrocarbons having carbon numbersof less than 5, and wherein a weight ratio of hydrocarbons having carbonnumbers from 2 through 4, to methane, is greater than approximately 0.3.4347. A mixture produced from a portion of a hydrocarbon containingformation, comprising: condensable hydrocarbons, wherein less than about5% by weight of the condensable hydrocarbons comprises hydrocarbonshaving a carbon number greater than about 25; and wherein thecondensable hydrocarbons further comprise aromatic compounds, whereinmore than about 20% by weight of the condensable hydrocarbons comprisesaromatic compounds.
 4348. The mixture of claim 4347, further comprisingnon-condensable hydrocarbons, wherein the non-condensable hydrocarbonscomprise hydrocarbons having carbon numbers of less than 5, and whereina weight ratio of hydrocarbons having carbon numbers from 2 through 4,to methane, is greater than approximately
 1. 4349. The mixture of claim4347, wherein the condensable hydrocarbons further comprise olefins, andwherein about 0.1% by weight to about 15% by weight of the condensablehydrocarbons are olefins.
 4350. The mixture of claim 4347, furthercomprising non-condensable hydrocarbons, wherein a molar ratio of etheneto ethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 4351. The mixture of claim 4347, wherein the condensablehydrocarbons further comprise nitrogen, and wherein less than about 1%by weight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 4352. The mixture of claim 4347, wherein thecondensable hydrocarbons further comprise oxygen, and wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4353. The mixture of claim 4347,wherein the condensable hydrocarbons further comprise sulfur, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 4354. The mixture ofclaim 4347, wherein the condensable hydrocarbons further comprise oxygencontaining compounds, wherein about 5% by weight to about 30% by weightof the condensable hydrocarbons comprise oxygen containing compounds,and wherein the oxygen containing compounds comprise phenols.
 4355. Themixture of claim 4347, wherein the condensable hydrocarbons furthercomprise multi-ring aromatics, and wherein less than about 5% by weightof the condensable hydrocarbons comprises multi-ring aromatics with morethan two rings.
 4356. The mixture of claim 4347, wherein the condensablehydrocarbons further comprise asphaltenes, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4357.The mixture of claim 4347, wherein the condensable hydrocarbons comprisecycloalkanes, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4358. The mixture ofclaim 4347, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise hydrogen, and wherein the hydrogenis greater than about 10% by volume and less than about 80% by volume oft he non-condensable hydrocarbons.
 4359. The mixture of claim 4347,further comprising ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 4360. The mixture of claim4347, further comprising ammonia, and wherein the ammonia is used toproduce fertilizer.
 4361. The mixture of claim 4347, wherein thecondensable hydrocarbons further comprise olefins, and wherein about0.1% to about 5% by weight of the condensable hydrocarbons comprisesolefins.
 4362. The mixture of claim 4347, wherein the condensablehydrocarbons further comprises olefins, and wherein about 0.1% to about2% by weight of the condensable hydrocarbons comprises olefins. 4363.The mixture of claim 4347, wherein the condensable hydrocarbons furthercomprises multi-ring aromatic compounds, and wherein less than about 2%by weight of the condensable hydrocarbons comprises multi-ring aromaticcompounds.
 4364. The mixture of claim 4347, wherein the condensablehydrocarbons comprises oxygenated hydrocarbons, and wherein greater thanabout 1.5% by weight of the condensable hydrocarbons comprisesoxygenated hydrocarbons.
 4365. The mixture of claim 4347, wherein thecondensable hydrocarbons comprises oxygenated hydrocarbons, and whereingreater than about 25% by weight of the condensable component comprisesoxygenated hydrocarbons.
 4366. The mixture of claim 4347, furthercomprising non-condensable hydrocarbons, wherein the non-condensablehydrocarbons comprise H₂, and wherein greater than about 5% by weight ofthe non-condensable hydrocarbons comprises H₂.
 4367. The mixture ofclaim 4347, further comprising non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise H₂, and wherein greater than about15% by weight of the non-condensable hydrocarbons comprises H₂. 4368.The mixture of claim 4347, further comprising non-condensablehydrocarbons, wherein the non-condensable hydrocarbons compriseshydrocarbons having carbon numbers of less than 5, and wherein a weightratio of hydrocarbons having carbon numbers from 2 through 4, tomethane, is greater than approximately 0.3.
 4369. A mixture producedfrom a portion of a hydrocarbon containing formation, comprising:non-condensable hydrocarbons comprising hydrocarbons having carbonnumbers of less than about 5, wherein a weight ratio of the hydrocarbonshaving carbon number from 2 through 4, to methane, in the mixture isgreater than approximately 1; wherein the non-condensable hydrocarbonsfurther comprise H₂, wherein greater than about 15% by weight of thenon-condensable hydrocarbons comprises H₂; and condensable hydrocarbons,comprising: oxygenated hydrocarbons, wherein greater than about 1.5% byweight of the condensable hydrocarbons comprises oxygenatedhydrocarbons; olefins, wherein less than about 10% by weight of thecondensable hydrocarbons comprises olefins; and aromatic compounds,wherein greater than about 20% by weight of the condensable hydrocarbonscomprises aromatic compounds.
 4370. The mixture of claim 4369, whereinthe non-condensable hydrocarbons further comprise ethene and ethane, andwherein a molar ratio of ethene to ethane in the non-condensablehydrocarbons ranges from about 0.001 to about 0.15.
 4371. The mixture ofclaim 4369, wherein the condensable hydrocarbons further comprisenitrogen, and wherein less than about 1% by weight, when calculated onan atomic basis, of the condensable hydrocarbons is nitrogen.
 4372. Themixture of claim 4369, wherein the condensable hydrocarbons furthercomprise oxygen, and wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isoxygen.
 4373. The mixture of claim 4369, wherein the condensablehydrocarbons further comprise sulfur, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is sulfur.
 4374. The mixture of claim 4369, wherein thecondensable hydrocarbons further comprise oxygen containing compounds,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4375. The mixture of claim4369, wherein the condensable hydrocarbons comprise multi-ringaromatics, and wherein less than about 5% by weight of the condensablehydrocarbons comprises multi-ring aromatics with more than two rings.4376. The mixture of claim 4369, wherein the condensable hydrocarbonscomprise asphaltenes, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4377. The mixture of claim4369, wherein the condensable hydrocarbons comprise cycloalkanes, andwherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 4378. The mixture of claim 4369, whereinthe non-condensable hydrocarbons further comprises hydrogen, and whereingreater than about 10% by volume and less than about 80% by volume ofthe non-condensable hydrocarbons.
 4379. The mixture of claim 4369,further comprising ammonia, and wherein greater than about 0.05% byweight of the produced mixture is ammonia.
 4380. The mixture of claim4369, further comprising ammonia, and wherein the ammonia is used toproduce fertilizer.
 4381. The mixture of claim 4369, wherein thecondensable hydrocarbons further comprise hydrocarbons having a carbonnumber of greater than approximately 25, wherein less than about 15% byweight of the hydrocarbons have a carbon number greater thanapproximately
 25. 4382. The mixture of claim 4369, wherein about 0.1% toabout 5% by weight of the condensable hydrocarbons comprises olefins.4383. The mixture of claim 4369, wherein about 0.1% to about 2% byweight of the condensable hydrocarbons comprises olefins.
 4384. Themixture of claim 4369, wherein greater than about 25% by weight of thecondensable hydrocarbons comprises oxygenated hydrocarbons.
 4385. Themixture of claim 4369, wherein the mixture comprises hydrocarbons havinggreater than about 2 carbon atoms, and wherein the weight ratio ofhydrocarbons having greater than about 2 carbon atoms to methane isgreater than about 0.3.
 4386. A mixture produced from a portion of ahydrocarbon containing formation, comprising: condensable hydrocarbons,wherein less than about 5% by weight of the condensable hydrocarbonscomprises hydrocarbons having a carbon number greater than about 25;wherein the condensable hydrocarbons further comprise: oxygenatedhydrocarbons, wherein greater than about 5% by weight of the condensablehydrocarbons comprises oxygenated hydrocarbons; olefins, wherein lessthan about 10% by weight of the condensable hydrocarbons comprisesolefins; and aromatic compounds, wherein greater than about 30% byweight of the condensable hydrocarbons comprises aromatic compounds; andnon-condensable hydrocarbons comprising H₂, wherein greater than about15% by weight of the non-condensable hydrocarbons comprises H₂. 4387.The mixture of claim 4386, wherein the non-condensable hydrocarbonsfurther comprises hydrocarbons having carbon numbers of less than 5, andwherein a weight ratio of hydrocarbons having carbon numbers from 2through 4, to methane, is greater than approximately
 1. 4388. Themixture of claim 4386, wherein the non-condensable hydrocarbons compriseethene and ethane, and wherein a molar ratio of ethene to ethane in thenon-condensable hydrocarbons ranges from about 0.001 to about 0.15.4389. The mixture of claim 4386, wherein the condensable hydrocarbonsfurther comprise nitrogen, and wherein less than about 1% by weight,when calculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4390. The mixture of claim 4386, wherein the condensablehydrocarbons further comprise oxygen, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 4391. The mixture of claim 4386, wherein thecondensable hydrocarbons further comprise sulfur, and wherein less thanabout 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 4392. The mixture of claim 4386,wherein the condensable hydrocarbons further comprise oxygen containingcompounds, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 4393. Themixture of claim 4386, wherein the condensable hydrocarbons furthercomprise multi-ring aromatics, and wherein less than about 5% by weightof the condensable hydrocarbons comprises multi-ring aromatics with morethan two rings.
 4394. The mixture of claim 4386, wherein the condensablehydrocarbons further comprise asphaltenes, and wherein less than about0.3% by weight of the condensable hydrocarbons are asphaltenes. 4395.The mixture of claim 4386, wherein the condensable hydrocarbons comprisecycloalkanes, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4396. The mixture ofclaim 4386, wherein greater than about 10% by volume and less than about80% by volume of the non-condensable hydrocarbons is hydrogen.
 4397. Themixture of claim 4386, further comprising ammonia, and wherein greaterthan about 0.05% by weight of the produced mixture is ammonia.
 4398. Themixture of claim 4386, further comprising ammonia, and wherein theammonia is used to produce fertilizer.
 4399. The mixture of claim 4386,wherein about 0.1% to about 5% by weight of the condensable hydrocarbonscomprises olefins.
 4400. The mixture of claim 4386, wherein about 0.1%to about 2% by weight of the condensable hydrocarbons comprises olefins.4401. The mixture of claim 4386, wherein the condensable hydrocarbonscomprises oxygenated hydrocarbons, and wherein greater than about 15% byweight of the condensable hydrocarbons comprises oxygenatedhydrocarbons.
 4402. The mixture of claim 4386, wherein the mixturecomprises hydrocarbons having greater than about 2 carbon atoms, andwherein the weight ratio of hydrocarbons having greater than about 2carbon atoms to methane is greater than about 0.3.
 4403. A condensablemixture produced from a portion of a hydrocarbon containing formation,comprising: olefins, wherein about 0.1% by weight to about 15% by weightof the condensable mixture comprises olefins; oxygenated hydrocarbons,wherein less than about 15% by weight of the condensable mixturecomprises oxygenated hydrocarbons; and asphaltenes, wherein less thanabout 0.1% by weight of the condensable mixture comprises asphaltenes.4404. The mixture of claim 4403, wherein the condensable mixture furthercomprises hydrocarbons having a carbon number of greater thanapproximately 25, and wherein less than about 15 weight % of thehydrocarbons in the mixture have a carbon number greater thanapproximately
 25. 4405. The mixture of claim 4403, wherein about 0.1% byweight to about 5% by weight of the condensable mixture comprisesolefins.
 4406. The mixture of claim 4403, wherein the condensablemixture further comprises non-condensable hydrocarbons, wherein thenon-condensable hydrocarbons comprise ethene and ethane, and wherein amolar ratio of ethene to ethane in the non-condensable hydrocarbonsranges from about 0.001 to about 0.15.
 4407. The mixture of claim 4403,wherein the condensable mixture further comprises nitrogen, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable mixture is nitrogen.
 4408. The mixture of claim 4403,wherein the condensable mixture further comprises oxygen, and whereinless than about 1% by weight, when calculated on an atomic basis, of thecondensable mixture is oxygen.
 4409. The mixture of claim 4403, whereinthe condensable mixture further comprises to sulfur, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable mixture is sulfur.
 4410. The mixture of claim 4403, whereinthe condensable mixture further comprises oxygen containing compounds,wherein about 5% by weight to about 30% by weight of the condensablemixture comprise oxygen containing compounds, and wherein the oxygencontaining compounds comprise phenols.
 4411. The mixture of claim 4403,wherein the condensable mixture further comprises aromatic compounds,and wherein greater than about 20% by weight of the condensable mixtureare aromatic compounds.
 4412. The mixture of claim 4403, wherein thecondensable mixture further comprises multi-ring aromatics, and whereinless than about 5% by weight of the condensable hydrocarbons comprisesmulti-ring aromatics with more than two rings.
 4413. The mixture ofclaim 4403, wherein the condensable mixture further comprisescycloalkanes, and wherein about 5% by weight to about 30% by weight ofthe condensable mixture are cycloalkanes.
 4414. The mixture of claim4403, wherein the condensable mixture comprises non-condensablehydrocarbons, and wherein the non-condensable hydrocarbons comprisehydrogen, and wherein the hydrogen is greater than about 10% by volumeof the non-condensable hydrocarbons and wherein the hydrogen is lessthan about 80% by volume of the non-condensable hydrocarbons.
 4415. Themixture of claim 4403, further comprising ammonia, and wherein greaterthan about 0.05% by weight of the produced mixture is ammonia.
 4416. Themixture of claim 4403, further comprising ammonia, and wherein theammonia is used to produce fertilizer.
 4417. The mixture of claim 4403,wherein about 0.1% by weight to about 2% by weight of the condensablemixture comprises olefins.
 4418. A condensable mixture produced from aportion of a hydrocarbon containing formation, comprising: olefins,wherein about 0.1% by weight to about 2% by weight of the condensablemixture comprises olefins; multi-ring aromatics, wherein less than about2% by weight of the condensable mixture comprises multi-ring aromaticswith more than two rings; and oxygenated hydrocarbons, wherein greaterthan about 25% by weight of the condensable mixture comprises oxygenatedhydrocarbons.
 4419. The mixture of claim 4418, further comprisinghydrocarbons having a carbon number of greater than approximately 25,wherein less than about 5 weight % of the hydrocarbons in the mixturehave a carbon number greater than approximately
 25. 4420. The mixture ofclaim 4418, wherein the condensable mixture further comprises nitrogen,and wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is nitrogen.
 4421. The mixture ofclaim 4418, wherein the condensable mixture further comprises oxygen,and wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is oxygen.
 4422. The mixture ofclaim 4418, wherein the condensable mixture further comprises sulfur,and wherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 4423. The mixture ofclaim 4418, wherein the condensable mixture further comprises oxygencontaining compounds, wherein about 5% by weight to about 30% by weightof the condensable hydrocarbons comprise oxygen containing compounds,and wherein the oxygen containing compounds comprise phenols.
 4424. Themixture of claim 4418, wherein the condensable mixture further comprisesaromatic compounds, and wherein greater than about 20% by weight of thecondensable mixture are aromatic compounds.
 4425. The mixture of claim4418, wherein the condensable mixture further comprises condensablehydrocarbons, and wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4426. The mixture of claim4418, wherein the condensable mixture further comprises cycloalkanes,and wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons are cycloalkanes.
 4427. The mixture of claim 4418, furthercomprising ammonia, wherein greater than about 0.05% by weight of theproduced mixture is ammonia.
 4428. The mixture of claim 4418, furthercomprising ammonia, wherein the ammonia is used to produce fertilizer.4429. A mixture produced from a portion of a hydrocarbon containingformation, comprising: non-condensable hydrocarbons and H₂, whereingreater than about 10% by volume of the non-condensable hydrocarbons andH₂ comprises H₂; ammonia and water, wherein greater than about 0.5% byweight of the mixture comprises ammonia; and condensable hydrocarbons.4430. The mixture of claim 4429, wherein the non-condensablehydrocarbons further comprise hydrocarbons having carbon numbers of lessthan 5, and wherein a weight ratio of the hydrocarbons having carbonnumbers from 2 through 4 to methane, in the mixture is greater thanapproximately
 1. 4431. The mixture of claim 4429, wherein greater thanabout 0.1% by weight of the condensable hydrocarbons are olefins, andwherein less than about 15% by weight of the condensable hydrocarbonsare olefins.
 4432. The mixture of claim 4429, wherein thenon-condensable hydrocarbons further comprise ethene and ethane, whereina molar ratio of ethene to ethane in the non-condensable hydrocarbons isgreater than about 0.001, and wherein a molar ratio of ethene to ethanein the non-condensable hydrocarbons is less than about 0.15.
 4433. Themixture of claim 4429, wherein less than about 1% by weight, whencalculated on an atomic basis, of the condensable hydrocarbons isnitrogen.
 4434. The mixture of claim 4429, wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is oxygen.
 4435. The mixture of claim 4429, wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is sulfur.
 4436. The mixture of claim 4429,wherein about 5% by weight to about 30% by weight of the condensablehydrocarbons comprise oxygen containing compounds, and wherein theoxygen containing compounds comprise phenols.
 4437. The mixture of claim4429, wherein greater than about 20% by weight of the condensablehydrocarbons are aromatic compounds.
 4438. The mixture of claim 4429,wherein less than about 5% by weight of the condensable hydrocarbonscomprises multi-ring aromatics with more than two rings.
 4439. Themixture of claim 4429, wherein less than about 0.3% by weight of thecondensable hydrocarbons are asphaltenes.
 4440. The mixture of claim4429, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons are cycloalkanes.
 4441. The mixture of claim4429, wherein the H₂ is less than about 80% by volume of thenon-condensable hydrocarbons and H₂.
 4442. The mixture of claim 4429,wherein the condensable hydrocarbons further comprise sulfur containingcompounds.
 4443. The mixture of claim 4429, wherein the ammonia is usedto produce fertilizer.
 4444. The mixture of claim 4429, wherein lessthan about 5% of the condensable hydrocarbons have carbon numbersgreater than
 25. 4445. The mixture of claim 4429, wherein thecondensable hydrocarbons comprise olefins, wherein greater than aboutabout 0.001% by weight of the condensable hydrocarbons comprise olefins,and wherein less than about 15% by weight of the condensablehydrocarbons comprise olefins.
 4446. The mixture of claim 4429, whereinthe condensable hydrocarbons comprise olefins, wherein greater thanabout about 0.001% by weight of the condensable hydrocarbons compriseolefins, and wherein less than about 10% by weight of the condensablehydrocarbons comprise olefins.
 4447. The mixture of claim 4429, whereinthe condensable hydrocarbons comprise oxygenated hydrocarbons, andwherein greater than about 1.5% by weight of the condensablehydrocarbons comprises oxygenated hydrocarbons.
 4448. The mixture ofclaim 4429, wherein the condensable hydrocarbons further comprisenitrogen containing compounds.
 4449. A method of treating a hydrocarboncontaining formation in situ comprising providing heat from three ormore heat sources to at least a portion of the formation, wherein threeor more of the heat sources are located in the formation in a unit ofheat sources, and wherein the unit of heat sources comprises atriangular pattern.
 4450. The method of claim 4449, wherein three ormore of the heat sources are located in the formation in a plurality ofthe units, and wherein the plurality of units are repeated over an areaof the formation to form a repetitive pattern of units.
 4451. The methodof claim 4449, wherein three or more of the heat sources are located inthe formation in a plurality of the units, wherein the plurality ofunits are repeated over an area of the formation to form a repetitivepattern of units, and wherein a ratio of heat sources in the repetitivepattern of units to production wells in the repetitive pattern is lessthan approximately
 5. 4452. The method of claim 4449, wherein three ormore of the heat sources are located in the formation in a plurality ofthe units, wherein the plurality of units are repeated over an area ofthe formation to form a repetitive pattern of units, wherein three ormore production wells are located within an area defined by theplurality of units, wherein the three or more production wells arelocated in the formation in a unit of production wells, and wherein theunit of production wells comprises a triangular pattern.
 4453. Themethod of claim 4449, wherein three or more of the heat sources arelocated in the formation in a plurality of the units, wherein theplurality of units are repeated over an area of the formation to form arepetitive pattern of units, wherein three or more injection wells arelocated within an area defined by the plurality of units, wherein thethree or more injection wells are located in the formation in a unit ofinjection wells, and wherein the unit of injection wells comprises atriangular pattern.
 4454. The method of claim 4449, wherein three ormore of the heat sources are located in the formation in a plurality ofthe units, wherein the plurality of units are repeated over an area ofthe formation to form a repetitive pattern of units, wherein three ormore production wells and three or more injection wells are locatedwithin an area defined by the plurality of units, wherein the three ormore production wells are located in the formation in a unit ofproduction wells, wherein the unit of production wells comprises a firsttriangular pattern, wherein the three or more injection wells arelocated in the formation in a unit of injection wells, wherein the unitof injection wells comprises a second triangular pattern, and whereinthe first triangular pattern is substantially different than the secondtriangular pattern.
 4455. The method of claim 4449, wherein three ormore of the heat sources are located in the formation in a plurality ofthe units, wherein the plurality of units are repeated over an area ofthe formation to form a repetitive pattern of units, wherein three ormore monitoring wells are located within an area defined by theplurality of units, wherein the three or more monitoring wells arelocated in the formation in a unit of monitoring wells, and wherein theunit of monitoring wells comprises a triangular pattern.
 4456. Themethod of claim 4449, wherein a production well is located in an areadefined by the unit of heat sources.
 4457. The method of claim 4449,wherein three or more of the heat sources are located in the formationin a first unit and a second unit, wherein the first unit is adjacent tothe second unit, and wherein the first unit is inverted with respect tothe second unit.
 4458. The method of claim 4449, wherein a distancebetween each of the heat sources in the unit of heat sources varies byless than about 20%.
 4459. The method of claim 4449, wherein a distancebetween each of the heat sources in the unit of heat sources isapproximately equal.
 4460. The method of claim 4449, wherein providingheat from three or more heat sources comprises substantially uniformlyproviding heat to at least the portion of the formation.
 4461. Themethod of claim 4449, wherein the heated portion comprises asubstantially uniform temperature distribution.
 4462. The method ofclaim 4449, wherein the heated portion comprises a substantially uniformtemperature distribution, and wherein a difference between a highesttemperature in the heated portion and a lowest temperature in the heatedportion comprises less than about 200° C.
 4463. The method of claim4449, wherein a temperature at an outer lateral boundary of thetriangular pattern and a temperature at a center of the triangularpattern are approximately equal.
 4464. The method of claim 4449, whereina temperature at an outer lateral boundary of the triangular pattern anda temperature at a center of the triangular pattern increasesubstantially linearly after an initial period of time, and wherein theinitial period of time comprises less than approximately 3 months. 4465.The method of claim 4449, wherein a time required to increase an averagetemperature of the heated portion to a selected temperature with thetriangular pattern of heat sources is substantially less than a timerequired to increase the average temperature of the heated portion tothe selected temperature with a hexagonal pattern of heat sources, andwherein a space between each of the heat sources in the triangularpattern is approximately equal to a space between each of the heatsources in the hexagonal pattern.
 4466. The method of claim 4449,wherein a time required to increase a temperature at a coldest pointwithin the heated portion to a selected temperature with the triangularpattern of heat sources is substantially less than a time required toincrease a temperature at the coldest point within the heated portion tothe selected temperature with a hexagonal pattern of heat sources, andwherein a space between each of the heat sources in the triangularpattern is approximately equal to a space between each of the heatsources in the hexagonal pattern.
 4467. The method of claim 4449,wherein a time required to increase a temperature at a coldest pointwithin the heated portion to a selected temperature with the triangularpattern of heat sources is substantially less than a time required toincrease a temperature at the coldest point within the heated portion tothe selected temperature with a hexagonal pattern of heat sources, andwherein a number of heat sources per unit area in the triangular patternis equal to the number of heat sources per unit are in the hexagonalpattern of heat sources.
 4468. The method of claim 4449, wherein a timerequired to increase a temperature at a coldest point within the heatedportion to a selected temperature with the triangular pattern of heatsources is substantially equal to a time required to increase atemperature at the coldest point within the heated portion to theselected temperature with a hexagonal pattern of heat sources, andwherein a space between each of the heat sources in the triangularpattern is approximately 5 m greater than a space between each of theheat sources in the hexagonal pattern.
 4469. The method of claim 4449,wherein providing heat from three or more heat sources to at least theportion of formation comprises: heating a selected volume (V) of thehydrocarbon containing formation from three or more of the heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinheat from three or more of the heat sources pyrolyzes at least somehydrocarbons within the selected volume of the formation; and whereinheating energy/day provided to the volume is equal to or less than P r,wherein Pwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) whereinPwr is the heating energy/day, h is an average heating rate of theformation, ρ_(B) is formation bulk density, and wherein the heating rateis less than about 10° C./day.
 4470. The method of claim 4449, whereinthree or more of the heat sources comprise electrical heaters.
 4471. Themethod of claim 4449, wherein three or more of the heat sources comprisesurface burners.
 4472. The method of claim 4449, wherein three or moreof the heat sources comprise flameless distributed combustors.
 4470. Themethod of claim 4449, wherein three or more of the heat sources comprisenatural distributed combustors.
 4474. The method of claim 4449, furthercomprising: allowing the heat to transfer from three or more of the heatsources to a selected section of the formation such that heat from threeor more of the heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation; and producing a mixture of fluidsfrom the formation.
 4475. The method of claim 4474, further comprisingcontrolling a temperature within at least a majority of the selectedsection of the formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 4476. The method of claim 4474, further comprisingcontrolling the heat such that an average heating rate of the selectedsection is less than about 1.0° C. per day during pyrolysis.
 4477. Themethod of claim 4474, wherein allowing the heat to transfer from threeor more of the heat sources to the selected section comprisestransferring heat substantially by conduction.
 4478. The method of claim4474, wherein providing heat from three or more of the heat sources toat least the portion of the formation comprises heating the selectedsection such that a thermal conductivity of at least a portion of theselected section is greater than about 0.5 W/m ° C.
 4479. The method ofclaim 4474, wherein the produced mixture comprises an API gravity of atleast 25°.
 4480. The method of claim 4474, wherein the produced mixturecomprises condensable hydrocarbons, and wherein about 0.1% by weight toabout 15% by weight of the condensable hydrocarbons are olefins. 4481.The method of claim 22, wherein the produced mixture comprisesnon-condensable hydrocarbons, and wherein a molar ratio of ethene toethane in the non-condensable hydrocarbons ranges from about 0.001 toabout 0.15.
 4482. The method of claim 4474, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 1% byweight, when calculated on an atomic basis, of the condensablehydrocarbons is nitrogen.
 4483. The method of claim 4474, wherein theproduced mixture comprises condensable hydrocarbons, and wherein lessthan about 1% by weight, when calculated on an atomic basis, of thecondensable hydrocarbons is oxygen.
 4484. The method of claim 4474,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 1% by weight, when calculated on an atomicbasis, of the condensable hydrocarbons is sulfur.
 4485. The method ofclaim 4474, wherein the produced mixture comprises condensablehydrocarbons, wherein about 5% by weight to about 30% by weight of thecondensable hydrocarbons comprise oxygen containing compounds, andwherein the oxygen containing compounds comprise phenols.
 4486. Themethod of claim 4474, wherein the produced mixture comprises condensablehydrocarbons, and wherein greater than about 20% by weight of thecondensable hydrocarbons are aromatic compounds.
 4487. The method ofclaim 4474, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 5% by weight of thecondensable hydrocarbons comprises multi-ring aromatics with more thantwo rings.
 4488. The method of claim 4474, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 0.1% byweight of the condensable hydrocarbons are asphaltenes.
 4489. The methodof claim 4474, wherein the produced mixture comprises condensablehydrocarbons, and wherein about 5% by weight to about 30% by weight ofthe condensable hydrocarbons are cycloalkanes.
 4490. The method of claim4474, wherein the produced mixture comprises a non-condensablecomponent, wherein the non-condensable component comprises hydrogen,wherein the hydrogen is greater than about 10% by volume of thenon-condensable component, and wherein the hydrogen is less than about80% by volume of the non-condensable component.
 4491. The method ofclaim 4474, wherein the produced mixture comprises ammonia, and whereingreater than about 0.05% by weight of the produced mixture is ammonia.4492. The method of claim 4474, wherein the produced mixture comprisesammonia, and wherein the ammonia is used to produce fertilizer. 4493.The method of claim 4474, further comprising controlling formationconditions to produce a mixture of hydrocarbon fluids and H₂, wherein apartial pressure of H₂ within the mixture is greater than about 2.0 barabsolute.
 4494. The method of claim 4474, further comprising altering apressure within the formation to inhibit production of hydrocarbons fromthe formation having carbon numbers greater than about
 25. 4495. Themethod of claim 4474, further comprising controlling formationconditions by recirculating a portion of hydrogen from the mixture intothe formation.
 4496. The method of claim 4474, further comprising:providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 4497. The method of claim 4474, furthercomprising: producing hydrogen from the formation; and hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 4498. The method of claim 4474, whereinallowing the heat to transfer from three or more of the heat sources tothe selected section of the formation comprises increasing apermeability of a majority of the selected section to greater than about100 millidarcy.
 4499. The method of claim 4474, wherein allowing theheat to transfer from three or more of the heat sources to the selectedsection of the formation comprises substantially uniformly increasing apermeability of a majority of the selected section.
 4500. The method ofclaim 4474, further comprising controlling the heat from three of moreheat sources to yield greater than about 60% by weight of condensablehydrocarbons, as measured by the Fischer Assay.
 4501. The method ofclaim 4474, wherein producing the mixture comprises producing themixture in a production well, and wherein at least about 7 heat sourcesare disposed in the formation for each production well.
 4502. The methodof claim 4474, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,and wherein the unit of heat sources comprises a triangular pattern.4503. The method of claim 4474, further comprising providing heat fromthree or more heat sources to at least a portion of the formation,wherein three or more of the heat sources are located in the formationin a unit of heat sources, wherein the unit of heat sources comprises atriangular pattern, and wherein a plurality of the units are repeatedover an area of the formation to form a repetitive pattern of units.4504. A method for in situ production of synthesis gas from ahydrocarbon containing formation, comprising: heating a section of theformation to a temperature sufficient to allow synthesis gas generation,wherein a permeability of the section is substantially uniform andgreater than a permeability of an unheated section of the formation whenthe temperature sufficient to allow synthesis gas generation within theformation is achieved; providing a synthesis gas generating fluid to thesection to generate synthesis gas; and removing synthesis gas from theformation.
 4505. The method of claim 4504, wherein the permeability ofthe section is greater than about 100 millidarcy when the temperaturesufficient to allow synthesis gas generation within the formation isachieved.
 4506. The method of claim 4504, wherein the temperaturesufficient to allow synthesis gas generation ranges from approximately400° C. to approximately 1200° C.
 4507. The method of claim 4504,further comprising heating the section when providing the synthesis gasgenerating fluid to inhibit temperature decrease in the section due tosynthesis gas generation.
 4508. The method of claim 4504, whereinheating the section comprises convecting an oxidizing fluid into aportion of the section, wherein the temperature within the section isabove a temperature sufficient to support oxidation of carbon within thesection with the oxidizing fluid, and reacting the oxidizing fluid withcarbon in the section to generate heat within the section.
 4509. Themethod of claim 4508, wherein the oxidizing fluid comprises air. 4510.The method of claim 4509, wherein an amount of the oxidizing fluidconvected into the section is configured to inhibit formation of oxidesof nitrogen by maintaining a reaction temperature below a temperaturesufficient to produce oxides of nitrogen compounds.
 4511. The method ofclaim 4504, wherein heating the section comprises diffusing an oxidizingfluid to reaction zones adjacent to wellbores within the formation,oxidizing carbon within the reaction zone to generate heat, andtransferring the heat to the section.
 4512. The method of claim 4504,wherein heating the section comprises heating the section by transfer ofheat from one or more of electrical heaters.
 4513. The method of claim4504, wherein heating the section to a temperature sufficient to allowsynthesis gas generation and providing a synthesis gas generating fluidto the section comprises introducing steam into the section to heat theformation and to generate synthesis gas.
 4514. The method of claim 4504,further comprising controlling the heating of the section and provisionof the synthesis gas generating fluid to maintain a temperature withinthe section above the temperature sufficient to generate synthesis gas.4515. The method of claim 4504, further comprising: monitoring acomposition of the produced synthesis gas; and controlling heating ofthe section and provision of the synthesis gas generating fluid tomaintain the composition of the produced synthesis gas within a selectedrange.
 4516. The method of claim 4515, wherein the selected rangecomprises a ratio of H₂ to CO of about 2:1.
 4517. The method of claim4504, wherein the synthesis gas generating fluid comprises liquid water.4518. The method of claim 4504, wherein the synthesis gas generatingfluid comprises steam.
 4519. The method of claim 4504, wherein thesynthesis gas generating fluid comprises water and carbon dioxide, andwherein the carbon dioxide inhibits production of carbon dioxide fromcarbon containing material within the section.
 4520. The method of claim4519, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4521. The method of claim 4504, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.4522. The method of claim 4521, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4523. The method of claim 4504, whereinproviding the synthesis gas generating fluid to the section comprisesraising a water table of the formation to allow water to flow into thesection.
 4524. The method of claim 4504, wherein the synthesis gas isremoved from a producer well equipped with a heating source, and whereina portion of the heating source adjacent to a synthesis gas producingzone operates at a substantially constant temperature to promoteproduction of the synthesis gas wherein the synthesis gas has a selectedcomposition.
 4525. The method of claim 4524, wherein the substantiallyconstant temperature is about 700° C., and wherein the selectedcomposition has a H₂ to CO ratio of about 2:1.
 4526. The method of claim4504, wherein the synthesis gas generating fluid comprises water andhydrocarbons having carbon numbers less than 5, and wherein at least aportion of the hydrocarbons are subjected to a reaction within thesection to increase a H₂ concentration of the generated synthesis gas.4527. The method of claim 4504, wherein the synthesis gas generatingfluid comprises water and hydrocarbons having carbon numbers greaterthan 4, and wherein at least a portion of the hydrocarbons react withinthe section to increase an energy content of the synthesis gas removedfrom the formation.
 4528. The method of claim 4504, further comprisingmaintaining a pressure within the formation during synthesis gasgeneration, and passing produced synthesis gas through a turbine togenerate electricity.
 4529. The method of claim 4504, further comprisinggenerating electricity from the synthesis gas using a fuel cell. 4530.The method of claim 4504, further comprising generating electricity fromthe synthesis gas using a fuel cell, separating carbon dioxide from afluid exiting the fuel cell, and storing a portion of the separatedcarbon dioxide within a spent section of the formation.
 4531. The methodof claim 4504 further comprising using a portion of the synthesis gas asa combustion fuel to heat the formation.
 4532. The method of claim 4504,further comprising converting at least a portion of the producedsynthesis gas to condensable hydrocarbons using a Fischer-Tropschsynthesis process.
 4533. The method of claim 4504, further comprisingconverting at least a portion of the produced synthesis gas to methanol.4534. The method of claim 4504, further comprising converting at least aportion of the produced synthesis gas to gasoline.
 4535. The method ofclaim 4504, further comprising converting at least a portion of thesynthesis gas to methane using a catalytic methanation process. 4536.The method of claim 4504, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, and wherein the unit of heat sources comprises atriangular pattern.
 4537. The method of claim 4504, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, wherein the unit of heatsources comprises a triangular pattern, and wherein a plurality of theunits are repeated over an area of the formation to form a repetitivepattern of units.
 4538. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to substantially uniformlyincrease a permeability of the portion and to increase a temperature ofthe portion to a temperature sufficient to allow synthesis gasgeneration; providing a synthesis gas generating fluid to at least theportion of the selected section, wherein the synthesis gas generatingfluid comprises carbon dioxide; obtaining a portion of the carbondioxide of the synthesis gas generating fluid from the formation; andproducing synthesis gas from the formation.
 4539. The method of claim4538, wherein the temperature sufficient to allow synthesis gasgeneration is within a range from about 400° C. to about 1200° C. 4540.The method of claim 4538, further comprising using a second portion ofthe separated carbon dioxide as a flooding agent to produce hydrocarbonbed methane from a hydrocarbon containing formation.
 4541. The method ofclaim 4540, wherein the hydrocarbon containing formation is a deephydrocarbon containing formation over 760 m below ground surface. 4542.The method of claim 4540, wherein the hydrocarbon containing formationadsorbs some of the carbon dioxide to sequester the carbon dioxide.4543. The method of claim 4538, further comprising using a secondportion of the separated carbon dioxide as a flooding agent for enhancedoil recovery.
 4544. The method of claim 4538, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons undergoa reaction within the selected section to increase a H₂ concentrationwithin the produced synthesis gas.
 4545. The method of claim 4538,wherein the synthesis gas generating fluid comprises water andhydrocarbons having carbon numbers greater than 4, and wherein at leasta portion of the hydrocarbons react within the selected section toincrease an energy content of the produced synthesis gas.
 4546. Themethod of claim 4538, further comprising maintaining a pressure withinthe formation during synthesis gas generation, and passing producedsynthesis gas through a turbine to generate electricity.
 4547. Themethod of claim 4538, further comprising generating electricity from thesynthesis gas using a fuel cell.
 4548. The method of claim 4538, furthercomprising generating electricity from the synthesis gas using a fuelcell, separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent portionof the formation.
 4549. The method of claim 4538, further comprisingusing a portion of the synthesis gas as a combustion fuel for heatingthe formation.
 4550. The method of claim 4538, further comprisingconverting at least a portion of the produced synthesis gas tocondensable hydrocarbons using a Fischer-Tropsch synthesis process.4551. The method of claim 4538, further comprising converting at least aportion of the produced synthesis gas to methanol.
 4552. The method ofclaim 4538, further comprising converting at least a portion of theproduced synthesis gas to gasoline.
 4553. The method of claim 4538,further comprising converting at least a portion of the synthesis gas tomethane using a catalytic methanation process.
 4554. The method of claim4538, wherein a temperature of the one or more heat sources wellbore ismaintained at a temperature of less than approximately 700° C. toproduce a synthesis gas having a ratio of H₂ to carbon monoxide ofgreater than about
 2. 4555. The method of claim 4538, wherein atemperature of the one or more heat sources wellbore is maintained at atemperature of greater than approximately 700° C. to produce a synthesisgas having a ratio of H₂ to carbon monoxide of less than about
 2. 4556.The method of claim 4538, wherein a temperature of the one or more heatsources wellbore is maintained at a temperature of approximately 700° C.to produce a synthesis gas having a ratio of H₂ to carbon monoxide ofapproximately
 2. 4557. The method of claim 4538, wherein a heat sourceof the one or more of heat sources comprises an electrical heater. 4558.The method of claim 4538, wherein a heat source of the one or more heatsources comprises a natural distributor heater.
 4559. The method ofclaim 4538, wherein a heat source of the one or more heat sourcescomprises a flameless distributor combustor (FDC) heater, and whereinfluids are produced from the wellbore of the FDC heater through aconduit positioned within the wellbore.
 4560. The method of claim 4538,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 4561.The method of claim 4538, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 4562. A methodof in situ synthesis gas production, comprising: providing heat from oneor more flameless distributed combustor heaters to at least a firstportion of a carbon containing formation; allowing the heat to transferfrom the one or more heaters to a selected section of the formation suchthat the heat from the one or more heaters substantially uniformlyincreases a permeability of the selected section, and to raise atemperature of the selected section to a temperature sufficient togenerate synthesis gas; introducing a synthesis gas producing fluid intothe selected section to generate synthesis gas; and removing synthesisgas from the formation.
 4563. The method of claim 4562, wherein the oneor more heaters comprise at least two heaters, and wherein superpositionof heat from at least the two heaters substantially uniformly increasesa permeability of the selected section, and raises a temperature of theselected section to a temperature sufficient to generate synthesis gas.4564. The method of claim 4562, further comprising producing thesynthesis gas from the formation under pressure, and generatingelectricity from the produced synthesis gas by passing the producedsynthesis gas through a turbine.
 4565. The method of claim 4562, furthercomprising producing pyrolyzation products from the formation whenraising the temperature of the selected section to the temperaturesufficient to generate synthesis gas.
 4566. The method of claim 4562,further comprising separating a portion of carbon dioxide from theremoved synthesis gas, and storing the carbon dioxide within a spentportion of the formation.
 4567. The method of claim 4562, furthercomprising storing carbon dioxide within a spent portion of theformation, wherein an amount of carbon dioxide stored within the spentportion of the formation is equal to or greater than an amount of carbondioxide within the removed synthesis gas.
 4568. The method of claim4562, further comprising separating a portion of H₂ from the removedsynthesis gas; and using a portion of the separated H₂ as fuel for theone or more heaters.
 4569. The method of claim 4568, further comprisingusing a portion of exhaust products from one or more heaters as aportion of the synthesis gas producing fluid
 4570. The method of claim4562, further comprising using a portion of the removed synthesis gaswith a fuel cell to generate electricity.
 4571. The method of claim4570, wherein the fuel cell produces steam, and wherein a portion of thesteam is used as a portion of the synthesis gas producing fluid. 4572.The method of claim 4570, wherein the fuel cell produces carbon dioxide,and wherein a portion of the carbon dioxide is introduced into theformation to react with carbon within the formation to produce carbonmonoxide.
 4573. The method of claim 4570, wherein the fuel cell producescarbon dioxide, and storing an amount of carbon dioxide within a spentportion of the formation equal or greater to an amount of the carbondioxide produced by the fuel cell.
 4574. The method of claim 4562,further comprising using a portion of the removed synthesis gas as afeed product for formation of hydrocarbons.
 4575. The method of claim4562, wherein the synthesis gas producing fluid comprises hydrocarbonshaving carbon numbers less than 5, and wherein the hydrocarbons crackwithin the formation to increase an amount of H₂ within the generatedsynthesis gas.
 4576. The method of claim 4562, further comprisingproviding heat from three or more heat sources to at least a portion ofthe formation, wherein three or more of the heat sources are located inthe formation in a unit of heat sources, and wherein the unit of heatsources comprises a triangular pattern.
 4577. The method of claim 4562,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, whereinthe unit of heat sources comprises a triangular pattern, and wherein aplurality of the units are repeated over an area of the formation toform a repetitive pattern of units.
 4578. A method of treating ahydrocarbon containing formation, comprising: heating a portion of theformation with one or more electrical heaters to a temperaturesufficient to pyrolyze hydrocarbons within the portion; producingpyrolyzation fluid from the formation; separating a fuel cell feedstream from the pyrolyzation fluid; and directing the fuel cell feedstream to a fuel cell to produce electricity;
 4579. The method of claim4578, wherein the fuel cell is a molten carbonate fuel cell.
 4580. Themethod of claim 4578, wherein the fuel cell is a solid oxide fuel cell.4581. The method of claim 4578, further comprising using a portion ofthe produced electricity to power the electrical heaters.
 4582. Themethod of claim 4578, wherein heating the portion of the formation isperformed at a rate sufficient to increase a permeability of the portionand to produce a substantially uniform permeability within the portion.4583. The method of claim 4578, wherein the fuel cell feed streamcomprises H₂ and hydrocarbons having a carbon number of less than 5.4584. The method of claim 4578, wherein the fuel cell feed streamcomprises H₂ and hydrocarbons having a carbon number of less than 3.4585. The method of claim 4578, further comprising hydrogenating thepyrolyzation fluid with a portion of H₂ from the pyrolyzation fluid.4586. The method of claim 4578, wherein the hydrogenation is done insitu by directing the H₂ into the formation.
 4587. The method of claim4578, wherein the hydrogenation is done in a surface unit.
 4588. Themethod of claim 4578, further comprising directing hydrocarbon fluidhaving carbon numbers less than 5 adjacent to at least one of theelectrical heaters, cracking a portion of the hydrocarbons to produceH₂, and producing a portion of the hydrogen from the formation. 4589.The method of claim 4588, further comprising directing an oxidizingfluid adjacent to at least the one of the electrical heaters, oxidizingcoke deposited on or near the at least one of the electrical heaterswith the oxidizing fluid.
 4590. The method of claim 4578, furthercomprising storing CO₂ from the fuel cell within the formation. 4591.The method of claim 4590, wherein the CO₂ is adsorbed to carbon materialwithin a spent portion of the formation.
 4592. The method of claim 4578,further comprising cooling the portion to form a spent portion offormation.
 4593. The method of claim 4592, wherein cooling the portioncomprises introducing water into the portion to produce steam, andremoving steam from the formation.
 4594. The method of claim 4593,further comprising using a portion of the removed steam to heat a secondportion of the formation.
 4595. The method of claim 4593, furthercomprising using a portion of the removed steam as a synthesis gasproducing fluid in a second portion of the formation.
 4596. The methodof claim 4578, further comprising: heating the portion to a temperaturesufficient to support generation of synthesis gas after production ofthe pyrolyzation fluids; introducing a synthesis gas producing fluidinto the portion to generate synthesis gas; and removing a portion ofthe synthesis gas from the formation.
 4597. The method of claim 4596,further comprising producing the synthesis gas from the formation underpressure, and generating electricity from the produced synthesis gas bypassing the produced synthesis gas through a turbine.
 4598. The methodof claim 4596, further comprising using a first portion of the removedsynthesis gas as fuel cell feed.
 4599. The method of claim 4596, furthercomprising producing steam from operation of the fuel cell, and usingthe steam as part of the synthesis gas producing fluid.
 4600. The methodof claim 4596, further comprising using carbon dioxide from the fuelcell as a part of the synthesis gas producing fluid.
 4601. The method ofclaim 4596, further comprising using a portion of the synthesis gas toproduce hydrocarbon product.
 4602. The method of claim 4596, furthercomprising cooling the portion to form a spent portion of formation.4603. The method of claim 4602, wherein cooling the portion comprisesintroducing water into the portion to produce steam, and removing steamfrom the formation.
 4604. The method of claim 4603, further comprisingusing a portion of the removed steam to heat a second portion of theformation.
 4605. The method of claim 4603, further comprising using aportion of the removed steam as a synthesis gas producing fluid in asecond portion of the formation.
 4606. The method of claim 4578, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, and wherein the unitof heat sources comprises a triangular pattern.
 4607. The method ofclaim 4578, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,wherein the unit of heat sources comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 4608. A method for insitu production of synthesis gas from a hydrocarbon containingformation, comprising: providing heat from one or more heat sources toat least a portion of the formation; allowing the heat to transfer fromthe one or more heat sources to a selected section of the formation suchthat the heat from the one or more heat sources pyrolyzes at least someof the hydrocarbons within the selected section of the formation;producing pyrolysis products from the formation; heating at least aportion of the selected section to a temperature sufficient to generatesynthesis gas; providing a synthesis gas generating fluid to at leastthe portion of the selected section to generate synthesis gas; andproducing a portion of the synthesis gas from the formation.
 4609. Themethod of claim 4608, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from at leastthe two heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 4610. The method of claim 4608,further comprising allowing the heat to transfer from the one or moreheat sources to the selected section to substantially uniformly increasea permeability of the selected section.
 4611. The method of claim 4608,further comprising controlling heat transfer from the one or more heatsources to produce a permeability within the selected section of greaterthan about 100 millidarcy.
 4612. The method of claim 4608, furthercomprising heating at least the portion of the selected section whenproviding the synthesis gas generating fluid to inhibit temperaturedecrease within the selected section during synthesis gas generation.4613. The method of claim 4608, wherein the temperature sufficient toallow synthesis gas generation is within a range from approximately 400°C. to approximately 1200° C.
 4614. The method of claim 4608, whereinheating at least the portion of the selected section to a temperaturesufficient to allow synthesis gas generation comprises: heating zonesadjacent to wellbores of one or more heat sources with heaters disposedin the wellbores, wherein the heaters are configured to raisetemperatures of the zones to temperatures sufficient to support reactionof carbon-containing material within the zones with an oxidizing fluid;introducing the oxidizing fluid to the zones substantially by diffusion;allowing the oxidizing fluid to react with at least a portion of thecarbon-containing material within the zones to produce heat in thezones; and transferring heat from the zones to the selected section.4615. The method of claim 4608, wherein heating at least the portion ofthe selected section to a temperature sufficient to allow synthesis gasgeneration comprises: introducing an oxidizing fluid into the formationthrough a wellbore; transporting the oxidizing fluid substantially beconvection into the portion of the selected section, wherein the portionof the selected section is at a temperature sufficient to support anoxidization reaction with the oxidizing fluid; and reacting theoxidizing fluid within the portion of the selected section to generateheat and raise the temperature of the portion.
 4616. The method of claim4608, wherein the one or more heat sources comprise one or moreelectrical heaters disposed in the formation.
 4617. The method of claim4608, wherein one or more heat sources comprise one or more heaterwells, wherein at least one heater well comprises a conduit disposedwithin the formation, and further comprising heating the conduit byflowing a hot fluid through the conduit.
 4618. The method of claim 4608,wherein heating at least the portion of the selected section to atemperature sufficient to allow synthesis gas generation and providing asynthesis gas generating fluid to at least the portion of the selectedsection comprises introducing steam into the portion.
 4619. The methodof claim 4608, further comprising controlling the heating of at leastthe portion of selected section and provision of the synthesis gasgenerating fluid to maintain a temperature within at least the portionof the selected section above the temperature sufficient to generatesynthesis gas.
 4620. The method of claim 4608, further comprising:monitoring a composition of the produced synthesis gas; and controllingheating of at least the portion of selected section and provision of thesynthesis gas generating fluid to maintain the composition of theproduced synthesis gas within a desired range.
 4621. The method of claim4608, wherein the synthesis gas generating fluid comprises liquid water.4622. The method of claim 4608, wherein the synthesis gas generatingfluid comprises steam.
 4623. The method of claim 4608, wherein thesynthesis gas generating fluid comprises water and carbon dioxide,wherein the carbon dioxide inhibits production of carbon dioxide fromthe selected section.
 4624. The method of claim 4623, wherein a portionof the carbon dioxide within the synthesis gas generating fluidcomprises carbon dioxide removed from the formation.
 4625. The method ofclaim 4608, wherein the synthesis gas generating fluid comprises carbondioxide, and wherein a portion of the carbon dioxide reacts with carbonin the formation to generate carbon monoxide.
 4626. The method of claim4625, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4627. The method of claim 4608, wherein providing the synthesis gasgenerating fluid to at least the portion of the selected sectioncomprises raising a water table of the formation to allow water to flowinto the at least the portion of the selected section.
 4628. The methodof claim 4608, wherein the synthesis gas generating fluid compriseswater and hydrocarbons having carbon numbers less than 5, and wherein atleast a portion of the hydrocarbons are subjected to a reaction withinat least the portion of the selected section to increase a H₂concentration within the produced synthesis gas.
 4629. The method ofclaim 4608, wherein the synthesis gas generating fluid comprises waterand hydrocarbons having carbon numbers greater than 4, and wherein atleast a portion of the hydrocarbons react within at least the portion ofthe selected section to increase an energy content of the producedsynthesis gas.
 4630. The method of claim 4608, further comprisingmaintaining a pressure within the formation during synthesis gasgeneration, and passing produced synthesis gas through a turbine togenerate electricity.
 4631. The method of claim 4608, further comprisinggenerating electricity from the synthesis gas using a fuel cell. 4632.The method of claim 4608, further comprising generating electricity fromthe synthesis gas using a fuel cell, separating carbon dioxide from afluid exiting the fuel cell, and storing a portion of the separatedcarbon dioxide within a spent section of the formation.
 4633. The methodof claim 4608, further comprising using a portion of the synthesis gasas a combustion fuel for the one or more heat sources.
 4634. The methodof claim 4608, further comprising converting at least a portion of theproduced synthesis gas to condensable hydrocarbons using aFischer-Tropsch synthesis process.
 4635. The method of claim 4608,further comprising converting at least a portion of the producedsynthesis gas to methanol.
 4636. The method of claim 4608, furthercomprising converting at least a portion of the produced synthesis gasto gasoline.
 4637. The method of claim 4608, further comprisingconverting at least a portion of the synthesis gas to methane using acatalytic methanation process.
 4638. The method of claim 4608, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, and wherein the unitof heat sources comprises a triangular pattern.
 4639. The method ofclaim 4608, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,wherein the unit of heat sources comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 4640. A method for insitu production of synthesis gas from a hydrocarbon containingformation, comprising: heating a first portion of the formation topyrolyze some hydrocarbons within the first portion; allowing the heatto transfer from one or more heat sources to a selected section of theformation, pyrolyzing hydrocarbons within the selected section;producing fluid from the first portion, wherein the fluid comprises anaqueous fluid and a hydrocarbon fluid; heating a second portion of theformation to a temperature sufficient to allow synthesis gas generation;introducing at least a portion of the aqueous fluid to the secondsection after the section reaches the temperature sufficient to allowsynthesis gas generation; and producing synthesis gas from theformation.
 4641. The method of claim 4640, wherein the temperaturesufficient to allow synthesis gas generation ranges from approximately400° C. to approximately 1200° C.
 4642. The method of claim 4640,further comprising separating ammonia within the aqueous phase from theaqueous phase prior to introduction of at least the portion of theaqueous fluid to the second section.
 4643. The method of claim 4640,wherein a permeability of the second portion of the formation issubstantially uniform and greater than about 100 millidarcy when thetemperature sufficient to allow synthesis gas generation is achieved.4644. The method of claim 4640, further comprising heating the secondportion of the formation during introduction of at least the portion ofthe aqueous fluid to the second section to inhibit temperature decreasein the second section due to synthesis gas generation.
 4645. The methodof claim 4640, wherein heating the second portion of the formationcomprises convecting an oxidizing fluid into a portion of the secondportion that is above a temperature sufficient to support oxidation ofcarbon within the portion with the oxidizing fluid, and reacting theoxidizing fluid with carbon in the portion to generate heat within theportion.
 4646. The method of claim 4640, wherein heating the secondportion of the formation comprises diffusing an oxidizing fluid toreaction zones adjacent to wellbores within the formation, oxidizingcarbon within the reaction zones to generate heat, and transferring theheat to the second portion.
 4647. The method of claim 4640, whereinheating the second portion of the formation comprises heating the secondsection by transfer of heat from one or more electrical heaters. 4648.The method of claim 4640, wherein heating the second portion of theformation comprises heating the second section with a flamelessdistributor combustor.
 4649. The method of claim 4640, wherein heatingthe second portion of the formation comprises injecting steam into atleast the portion of the formation.
 4650. The method of claim 4640,wherein at least a portion of the aqueous fluid comprises a liquidphase.
 4651. The method of claim 4640, wherein the aqueous fluidcomprises a vapor phase.
 4652. The method of claim 4640, furthercomprising adding carbon dioxide to at least the portion of aqueousfluid to inhibit production of carbon dioxide from carbon within theformation.
 4653. The method of claim 4652, wherein a portion of thecarbon dioxide comprises carbon dioxide removed from the formation.4654. The method of claim 4640, further comprising adding hydrocarbonswith carbon numbers less than 5 to at least the portion of the aqueousfluid to increase a H₂ concentration within the produced synthesis gas.4655. The method of claim 4640, further comprising adding hydrocarbonswith carbon numbers less than 5 to at least the portion of the aqueousfluid to increase a H₂ concentration within the produced synthesis gas,wherein the hydrocarbons are obtained from the produced fluid.
 4656. Themethod of claim 4640, further comprising adding hydrocarbons greaterthan 4 to at least the portion of the aqueous fluid to increase energycontent of the produced synthesis gas.
 4657. The method of claim 4640,further comprising adding hydrocarbons greater than 4 to at least theportion of the aqueous fluid to increase energy content of the producedsynthesis gas, wherein the hydrocarbons are obtained from the producedfluid.
 4658. The method of claim 4640, further comprising maintaining apressure within the formation during synthesis gas generation, andpassing produced synthesis gas through a turbine to generateelectricity.
 4659. The method of claim 4640, further comprisinggenerating electricity from the synthesis gas using a fuel cell. 4660.The method of claim 4640, further comprising generating electricity fromthe synthesis gas using a fuel cell, separating carbon dioxide from afluid exiting the fuel cell, and storing a portion of the separatedcarbon dioxide within a spent portion of the formation.
 4661. The methodof claim 4640, further comprising using a portion of the synthesis gasas a combustion fuel for the one or more heat sources.
 4662. The methodof claim 4640, further comprising converting at least a portion of theproduced synthesis gas to condensable hydrocarbons using aFischer-Tropsch synthesis process.
 4663. The method of claim 4640,further comprising converting at least a portion of the producedsynthesis gas to methanol.
 4664. The method of claim 4640, furthercomprising converting at least a portion of the produced synthesis gasto gasoline.
 4665. The method of claim 4640, further comprisingconverting at least a portion of the synthesis gas to methane using acatalytic methanation process.
 4666. The method of claim 4640, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, and wherein the unitof heat sources comprises a triangular pattern.
 4667. The method ofclaim 4640, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,wherein the unit of heat sources comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 4668. A method for insitu production of synthesis gas from a carbon containing formation,comprising: heating a portion of the formation with one or more heatsources to create increased and substantially uniform permeabilitywithin a portion of the formation and to raise a temperature within theportion to a temperature sufficient to allow synthesis gas generation;providing a synthesis gas generating fluid into the portion through atleast one injection wellbore to generate synthesis gas from hydrocarbonsand the synthesis gas generating fluid; and producing synthesis gas fromat least one heat source wellbore in which is positioned proximate to aheat source of the one or more heat sources.
 4669. The method of claim4668, wherein the temperature sufficient to allow synthesis gasgeneration is within a range from about 400° C. to about 1200° C. 4670.The method of claim 4668, wherein creating a substantially uniformpermeability comprises heating the portion to a temperature within arange sufficient to pyrolyze hydrocarbons within the portion, raisingthe temperature within the portion at a rate of less than about 5° C.per day during pyrolyzation and removing a portion of pyrolyzed fluidfrom the formation.
 4671. The method of claim 4668, further comprisingremoving fluid from the formation through at least the one injectionwellbore prior to heating the selected section to the temperaturesufficient to allow synthesis gas generation.
 4672. The method of claim4668, wherein the injection wellbore comprises a wellbore of a heatsource in which is positioned a heat source of the one or more heatsources.
 4673. The method of claim 4668, further comprising heating theselected portion during providing the synthesis gas generating fluid toinhibit temperature decrease in at least the portion of the selectedsection due to synthesis gas generation.
 4674. The method of claim 4668,further comprising providing a portion of the heat needed to raise thetemperature sufficient to allow synthesis gas generation by convectingan oxidizing fluid to hydrocarbons within the selected section tooxidize a portion of the hydrocarbons and generate heat.
 4675. Themethod of claim 4668, further comprising controlling the heating of theselected section and provision of the synthesis gas generating fluid tomaintain a temperature within the selected section above the temperaturesufficient to generate synthesis gas.
 4676. The method of claim 4668,further comprising: monitoring a composition of the produced synthesisgas; and controlling heating of the selected section and provision ofthe synthesis gas generating fluid to maintain the composition of theproduced synthesis gas within a desired range.
 4677. The method of claim4668, wherein the synthesis gas generating fluid comprises liquid water.4678. The method of claim 4668, wherein the synthesis gas generatingfluid comprises steam.
 4679. The method of claim 4668, wherein thesynthesis gas generating fluid comprises steam to heat the selectedsection and to generate synthesis gas.
 4680. The method of claim 4668,wherein the synthesis gas generating fluid comprises water and carbondioxide, wherein the carbon dioxide inhibits production of carbondioxide from the selected section.
 4681. The method of claim 4680,wherein a portion of the carbon dioxide comprises carbon dioxide removedfrom the formation.
 4682. The method of claim 4668, wherein thesynthesis gas generating fluid comprises carbon dioxide, and wherein aportion of the carbon dioxide reacts with carbon in the formation togenerate carbon monoxide.
 4683. The method of claim 4682, wherein aportion of the carbon dioxide comprises carbon dioxide removed from theformation.
 4684. The method of claim 4668, wherein providing thesynthesis gas generating fluid to the selected section comprises raisinga water table of the formation to allow water to enter the selectedsection.
 4685. The method of claim 4668, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons undergoa reaction within the selected section to increase a H₂ concentrationwithin the produced synthesis gas.
 4686. The method of claim 4668,wherein the synthesis gas generating fluid comprises water andhydrocarbons having carbon numbers greater than 4, and wherein at leasta portion of the hydrocarbons react within the selected section toincrease an energy content of the produced synthesis gas.
 4687. Themethod of claim 4668, further comprising maintaining a pressure withinthe formation during synthesis gas generation, and passing producedsynthesis gas through a turbine to generate electricity.
 4688. Themethod of claim 4668, further comprising generating electricity from thesynthesis gas using a fuel cell.
 4689. The method of claim 4668, furthercomprising generating electricity from the synthesis gas using a fuelcell, separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent portionof the formation.
 4690. The method of claim 4668, further comprisingusing a portion of the synthesis gas as a combustion fuel for heatingthe formation.
 4691. The method of claim 4668, further comprisingconverting at least a portion of the produced synthesis gas tocondensable hydrocarbons using a Fischer-Tropsch synthesis process.4692. The method of claim 4668, further comprising converting at least aportion of the produced synthesis gas to methanol.
 4693. The method ofclaim 4668, further comprising converting at least a portion of theproduced synthesis gas to gasoline.
 4694. The method of claim 4668,further comprising converting at least a portion of the synthesis gas tomethane using a catalytic methanation process.
 4695. The method of claim4668, wherein a temperature of at least the one heat source wellbore ismaintained at a temperature of less than approximately 700° C. toproduce a synthesis gas having a ratio of H₂ to carbon monoxide ofgreater than about
 2. 4696. The method of claim 4668, wherein atemperature of at least the one heat source wellbore is maintained at atemperature of greater than approximately 700° C. to produce a synthesisgas having a ratio of H₂ to carbon monoxide of less than about
 2. 4697.The method of claim 4668, wherein a temperature of at least the one heatsource wellbore is maintained at a temperature of approximately 700° C.to produce a synthesis gas having a ratio of H₂ to car bon monoxide ofapproximately
 2. 4698. The method of claim 4668, wherein a heat sourceof the one or more heat sources comprises an electrical heater. 4699.The method of claim 4668, wherein a heat source of the one or more heatsources comprises a natural distributor heater.
 4700. The method ofclaim 4668, wherein a heat source of the one or more heat sourcescomprises a flameless distributor combustor (FDC) heater, and whereinfluids are produced from the wellbore of the FDC heater through aconduit positioned within the wellbore.
 4701. The method of claim 4668,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 4702.The method of claim 4668, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 4703. A methodof treating a hydrocarbon containing formation in situ, comprising:providing heat from one or more heat sources to at least a portion ofthe formation; allowing the heat to transfer from the one or more heatsources to a selected section of the formation such that the heat fromthe one or more heat sources pyrolyzes at least a portion of the carboncontaining material within the selected section of the formation;producing pyrolysis products from the formation; heating a first portionof a formation with one or more heat sources to a temperature sufficientto allow generation of synthesis gas; providing a first synthesis gasgenerating fluid to the first portion to generate a first synthesis gas;removing a portion of the first synthesis gas from the formation;heating a second portion of a formation with one more heat sources to atemperature sufficient to allow generation of synthesis gas having a H₂to CO ratio greater than a H₂ to CO ratio of the first synthesis gas;providing a second synthesis gas generating component to the secondportion to generate a second synthesis gas; removing a portion of thesecond synthesis gas from the formation; and blending a portion of thefirst synthesis gas with a portion of the second synthesis gas toproduce a blended synthesis gas having a selected H₂ to CO ratio. 4704.The method of claim 4703, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation.
 4705. The method of claim 4703,wherein the first synthesis gas generating fluid and second synthesisgas generating fluid are the same component.
 4706. The method of claim4703, further comprising controlling the temperature in the firstportion to control a composition of the first synthesis gas.
 4707. Themethod of claim 4703, further comprising controlling the temperature inthe second portion to control a composition of the second synthesis gas.4708. The method of claim 4703, wherein the selected ratio is controlledto be approximately 2:1 H₂ to CO.
 4709. The method of claim 4703,wherein the selected ratio is controlled to range from approximately1.8:1 to approximately 2.2:1 H₂ to CO.
 4710. The method of claim 4703,wherein the selected ratio is controlled to be approximately 3:1 H₂ toCO.
 4711. The method of claim 4703, wherein the selected ratio iscontrolled to range from approximately 2.8:1 to approximately 3.2:1 H₂to CO.
 4712. The method of claim 4703, further comprising providing atleast a portion of the produced blended synthesis gas to a condensablehydrocarbon synthesis process to produce condensable hydrocarbons. 4713.The method of claim 4712, wherein the condensable hydrocarbon synthesisprocess comprises a Fischer-Tropsch process.
 4714. The method of claim4713, further comprising cracking at least a portion of the condensablehydrocarbons to form middle distillates.
 4715. The method of claim 4703,further comprising providing at least a portion of the produced blendedsynthesis gas to a catalytic methanation process to produce methane.4716. The method of claim 4703, further comprising providing at least aportion of the produced blended synthesis gas to a methanol-synthesisprocess to produce methanol.
 4717. The method of claim 4703, furthercomprising providing at least a portion of the produced blendedsynthesis gas to a gasoline-synthesis process to produce gasoline. 4718.The method of claim 4703, wherein removing a portion of the secondsynthesis gas comprises withdrawing second synthesis gas through aproduction well, wherein a temperature of the production well adjacentto a second syntheses gas production zone is maintained at asubstantially constant temperature configured to produce secondsynthesis gas having the H₂ to CO ratio greater the first synthesis gas.4719. The method of claim 4703, wherein the first synthesis gasproducing fluid comprises CO₂ and wherein the temperature of the firstportion is at a temperature that will result in conversion of CO₂ andcarbon from the first portion to CO to generate a CO rich firstsynthesis gas.
 4720. The method of claim 4703, wherein the secondsynthesis gas producing fluid comprises water and hydrocarbons havingcarbon numbers less than 5, and wherein at least a portion of thehydrocarbons react within the formation to increase a H₂ concentrationwithin the produced second synthesis gas.
 4721. The method of claim4703, wherein blending a portion of the first synthesis gas with aportion of the second synthesis gas comprises producing an intermediatemixture having a H₂ to CO mixture of less than the selected ratio, andsubjecting the intermediate mixture to a shift reaction to reduce anamount of CO and increase an amount of H₂ to produce the selected ratioof H₂ to CO.
 4722. The method of claim 4703, further comprising removingan excess of first synthesis gas from the first portion to have anexcess of CO, subjecting the first synthesis gas to a shift reaction toreduce an amount of CO and increase an amount of H₂ before blending thefirst synthesis gas with the second synthesis gas.
 4723. The method ofclaim 4703, further comprising removing the first synthesis gas from theformation under pressure, and passing removed first synthesis gasthrough a turbine to generate electricity.
 4724. The method of claim4703, further comprising removing the second synthesis gas from theformation under pressure, and passing removed second synthesis gasthrough a turbine to generate electricity.
 4725. The method of claim4703, further comprising generating electricity from the blendedsynthesis gas using a fuel cell.
 4726. The method of claim 4703, furthercomprising generating electricity from the blended synthesis gas using afuel cell, separating carbon dioxide from a fluid exiting the fuel cell,and storing a portion of the separated carbon dioxide within a spentportion of the formation.
 4727. The method of claim 4703, furthercomprising using at least a portion of the blended synthesis gas as acombustion fuel for heating the formation.
 4728. The method of claim4703, further comprising allowing the heat to transfer from the one ormore heat sources to the selected section to substantially uniformlyincrease a permeability of the selected section.
 4729. The method ofclaim 4703, further comprising controlling heat transfer from the one ormore heat sources to produce a permeability within the selected sectionof greater than about 100 millidarcy.
 4730. The method of claim 4703,further comprising heating at least the portion of the selected sectionwhen providing the synthesis gas generating fluid to inhibit temperaturedecrease within the selected section during synthesis gas generation.4731. The method of claim 4703, wherein the temperature sufficient toallow synthesis gas generation is within a range from approximately 400°C. to approximately 1200° C.
 4732. The method of claim 4703, whereinheating the first a portion of the selected section to a temperaturesufficient to allow synthesis gas generation comprises: heating zonesadjacent to wellbores of one or more heat sources with heaters disposedin the wellbores, wherein the heaters are configured to raisetemperatures of the zones to temperatures sufficient to support reactionof carbon-containing material within the zones with an oxidizing fluid;introducing the oxidizing fluid to the zones substantially by diffusion;allowing the oxidizing fluid to react with at least a portion of thecarbon-containing material within the zones to produce heat in thezones; and transferring heat from the zones to the selected section.4733. The method of claim 4703, wherein heating the second portion ofthe selected section to a temperature sufficient to allow synthesis gasgeneration comprises: heating zones adjacent to wellbores of one or moreheat sources with heaters disposed in the wellbores, wherein the heatersare configured to raise temperatures of the zones to temperaturessufficient to support reaction of carbon-containing material within thezones with an oxidizing fluid; introducing the oxidizing fluid to thezones substantially by diffusion; allowing the oxidizing fluid to reactwith at least a portion of the carbon-containing material within thezones to produce heat in the zones; and transferring heat from the zonesto the selected section.
 4734. The method of claim 4703, wherein heatingthe first portion of the selected section to a temperature sufficient toallow synthesis gas generation comprises: introducing an oxidizing fluidinto the formation through a wellbore; transporting the oxidizing fluidsubstantially by convection into the first portion of the selectedsection, wherein the first portion of the selected section is at atemperature sufficient to support an oxidization reaction with theoxidizing fluid; and reacting the oxidizing fluid within the firstportion of the selected section to generate heat and raise thetemperature of the first portion.
 4735. The method of claim 4703,wherein heating the second portion of the selected section to atemperature sufficient to allow synthesis gas generation comprises:introducing an oxidizing fluid into the formation through a wellbore;transporting the oxidizing fluid substantially by convection into thesecond portion of the selected section, wherein the second portion ofthe selected section is at a temperature sufficient to support anoxidization reaction with the oxidizing fluid; and reacting theoxidizing fluid within the second portion of the selected section togenerate heat and raise the temperature of the second portion.
 4736. Themethod of claim 4703, wherein the one or more heat sources comprise oneor more electrical heaters disposed in the formation.
 4737. The methodof claim 4703, wherein the one or more heat sources comprises one ormore natural distributor combustors.
 4738. The method of claim 4703,wherein the one or more heat sources comprise one or more heater wells,wherein at least one heater well comprises a conduit disposed within theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 4739. The method of claim 4703, whereinheating the first portion of the selected section to a temperaturesufficient to allow synthesis gas generation and providing a firstsynthesis gas generating fluid to the first portion of the selectedsection comprises introducing steam into the first portion.
 4740. Themethod of claim 4703, wherein heating the second portion of the selectedsection to a temperature sufficient to allow synthesis gas generationand providing a second synthesis gas generating fluid to the secondportion of the selected section comprises introducing steam into thesecond portion.
 4741. The method of claim 4703, further comprisingcontrolling the heating of the first portion of selected section andprovision of the first synthesis gas generating fluid to maintain atemperature within the first portion of the selected section above thetemperature sufficient to generate synthesis gas.
 4742. The method ofclaim 4703, further comprising controlling the heating of the secondportion of selected section and provision of the second synthesis gasgenerating fluid to maintain a temperature within the second portion ofthe selected section above the temperature sufficient to generatesynthesis gas.
 4743. The method of claim 4703, wherein the firstsynthesis gas generating fluid comprises liquid water.
 4744. The methodof claim 4703, wherein the second synthesis gas generating fluidcomprises liquid water.
 4745. The method of claim 4703, wherein thefirst synthesis gas generating fluid comprises steam.
 4746. The methodof claim 4703, wherein the second synthesis gas generating fluidcomprises steam.
 4747. The method of claim 4703, wherein the firstsynthesis gas generating fluid comprises water and carbon dioxide,wherein the carbon dioxide inhibits production of carbon dioxide fromthe selected section.
 4748. The method of claim 4747, wherein a portionof the carbon dioxide within the first synthesis gas generating fluidcomprises carbon dioxide removed from the formation.
 4749. The method ofclaim 4703, wherein the second synthesis gas generating fluid compriseswater and carbon dioxide, wherein the carbon dioxide inhibits productionof carbon dioxide from the selected section.
 4750. The method of claim4749, wherein a portion of the carbon dioxide within the secondsynthesis gas generating fluid comprises carbon dioxide removed from theformation.
 4751. The method of claim 4703, wherein the first synthesisgas generating fluid comprises carbon dioxide, and wherein a portion ofthe carbon dioxide reacts with carbon in the formation to generatecarbon monoxide.
 4752. The method of claim 4751, wherein a portion ofthe carbon dioxide within the first synthesis gas generating fluidcomprises carbon dioxide removed from the formation.
 4753. The method ofclaim 4703, wherein the second synthesis gas generating fluid comprisescarbon dioxide, and wherein a portion of the carbon dioxide reacts withcarbon in the formation to generate carbon monoxide.
 4754. The method ofclaim 4753, wherein a portion of the carbon dioxide within the secondsynthesis gas generating fluid comprises carbon dioxide removed from theformation.
 4755. The method of claim 4703, wherein providing the firstsynthesis gas generating fluid to the first portion of the selectedsection comprises raising a water table of the formation to allow waterto flow into the first portion of the selected section.
 4756. The methodof claim 4703, wherein providing the second synthesis gas generatingfluid to the second portion of the selected section comprises raising awater table of the formation to allow water to flow into the secondportion of the selected section.
 4757. The method of claim 4703, whereinthe first synthesis gas generating fluid comprises water andhydrocarbons having carbon numbers less than 5, and wherein at least aportion of the hydrocarbons are subjected to a reaction within the firstportion of the selected section to increase a H₂ concentration withinthe produced first synthesis gas.
 4758. The method of claim 4703,wherein the second synthesis gas generating fluid comprises water andhydrocarbons having carbon numbers less than 5, and wherein at least aportion of the hydrocarbons are subjected to a reaction within thesecond portion of the selected section to increase a H₂ concentrationwithin the produced second synthesis gas.
 4759. The method of claim4703, wherein the first synthesis gas generating fluid comprises waterand hydrocarbons having carbon numbers greater than 4, and wherein atleast a portion of the hydrocarbons react within the first portion ofthe selected section to increase an energy content of the produced firstsynthesis gas.
 4760. The method of claim 4703, wherein the secondsynthesis gas generating fluid comprises water and hydrocarbons havingcarbon numbers greater than 4, and wherein at least a portion of thehydrocarbons react within at least the second portion of the selectedsection to increase an energy content of the second produced synthesisgas.
 4761. The method of claim 4703, further comprising maintaining apressure within the formation during synthesis gas generation, andpassing produced blended synthesis gas through a turbine to generateelectricity.
 4762. The method of claim 4703, further comprisinggenerating electricity from the blended synthesis gas using a fuel cell.4763. The method of claim 4703, further comprising generatingelectricity from the blended synthesis gas using a fuel cell, separatingcarbon dioxide from a fluid exiting the fuel cell, and storing a portionof the separated carbon dioxide within a spent section of the formation.4764. The method of claim 4703, further comprising using a portion ofthe blended synthesis gas as a combustion fuel for the one or more heatsources.
 4765. The method of claim 4703, further comprising using aportion of the first synthesis gas as a combustion fuel for the one ormore heat sources.
 4766. The method of claim 4703, further comprisingusing a portion of the second synthesis gas as a combustion fuel for theone or more heat sources.
 4767. The method of claim 4703, furthercomprising using a portion of the blended synthesis gas as a combustionfuel for the one or more heat sources.
 4768. A method of treating ahydrocarbon containing formation in situ, comprising: providing heatfrom one or more heat sources to at least a portion of the formation;allowing the heat to transfer from the one or more heat sources to aselected section of the formation such that the heat from the one ormore heat sources pyrolyzes at least some of the hydrocarbons within theselected section of the formation; producing pyrolysis products from theformation; heating at least a portion of the selected section to atemperature sufficient to generate synthesis gas; controlling atemperature of at least a portion of the selected section to generatesynthesis gas having a selected H₂ to CO ratio; providing a synthesisgas generating fluid to at least the portion of the selected section togenerate synthesis gas; and producing a portion of the synthesis gasfrom the formation.
 4769. The method of claim 4768, wherein the one ormore heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation.4770. The method of claim 4768, wherein the selected ratio is controlledto be approximately 2:1 H₂ to CO.
 4771. The method of claim 4768,wherein the selected ratio is controlled to range from approximately1.8:1 to approximately 2.2:1 H₂ to CO.
 4772. The method of claim 4768,wherein the selected ratio is controlled to be approximately 3:1 H₂ toCO.
 4773. The method of claim 4768, wherein the selected ratio iscontrolled to range from approximately 2.8:1 to approximately 3.2:1 H₂to CO.
 4774. The method of claim 4768, further comprising providing atleast a portion of the produced synthesis gas to a condensablehydrocarbon synthesis process to produce condensable hydrocarbons. 4775.The method of claim 4774, wherein the condensable hydrocarbon synthesisprocess comprises a Fischer-Tropsch process.
 4776. The method of claim4775, further comprising cracking at least a portion of the condensablehydrocarbons to form middle distillates.
 4777. The method of claim 4768,further comprising providing at least a portion of the producedsynthesis gas to a catalytic methanation process to produce methane.4778. The method of claim 4768, further comprising providing at least aportion of the produced synthesis gas to a methanol-synthesis process toproduce methanol.
 4779. The method of claim 4768, further comprisingproviding at least a portion of the produced synthesis gas to agasoline-synthesis process to produce gasoline.
 4780. The method ofclaim 4768, further comprising allowing the heat to transfer from theone or more heat sources to the selected section to substantiallyuniformly increase a permeability of the selected section.
 4781. Themethod of claim 4768, further comprising controlling heat transfer fromthe one or more heat sources to produce a permeability within theselected section of greater than about 100 millidarcy.
 4782. The methodof claim 4768, further comprising heating at least the portion of theselected section when providing the synthesis gas generating fluid toinhibit temperature decrease within the selected section duringsynthesis gas generation.
 4783. The method of claim 4768, wherein thetemperature sufficient to allow synthesis gas generation is within arange from approximately 400° C. to approximately 1200° C.
 4784. Themethod of claim 4768, wherein heating at least the portion of theselected section to a temperature sufficient to allow synthesis gasgeneration comprises: heating zones adjacent to wellbores of one or moreheat sources with heaters disposed in the wellbores, wherein the heatersare configured to raise temperatures of the zones to temperaturessufficient to support reaction of carbon-containing material within thezones with an oxidizing fluid; introducing the oxidizing fluid to thezones substantially by diffusion; allowing the oxidizing fluid to reactwith at least a portion of the carbon-containing material within thezones to produce heat in the zones; and transferring heat from the zonesto the selected section.
 4785. The method of claim 4768, wherein heatingat least the portion of the selected section to a temperature sufficientto allow synthesis gas generation comprises: introducing an oxidizingfluid into the formation through a wellbore; transporting the oxidizingfluid substantially by convection into the portion of the selectedsection, wherein the portion of the selected section is at a temperaturesufficient to support an oxidization reaction with the oxidizing fluid;and reacting the oxidizing fluid within the portion of the selectedsection to generate heat and raise the temperature of the portion. 4786.The method of claim 4768, wherein the one or more heat sources compriseone or more electrical heaters disposed in the formation.
 4787. Themethod of claim 4768, wherein the one or more heat sources comprises oneor more natural distributor combustors.
 4788. The method of claim 4768,wherein the one or more heat sources comprise one or more heater wells,wherein at least one heater well comprises a conduit disposed within theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 4789. The method of claim 4768, whereinheating at least the portion of the selected section to a temperaturesufficient to allow synthesis gas generation and providing a synthesisgas generating fluid to at least the portion of the selected sectioncomprises introducing steam into the portion.
 4790. The method of claim4768, further comprising controlling the heating of at least the portionof selected section and provision of the synthesis gas generating fluidto maintain a temperature within at least the portion of the selectedsection above the temperature sufficient to generate synthesis gas.4791. The method of claim 4768, wherein the synthesis gas generatingfluid comprises liquid water.
 4792. The method of claim 4768, whereinthe synthesis gas generating fluid comprises steam.
 4793. The method ofclaim 4768, wherein the synthesis gas generating fluid comprises waterand carbon dioxide, wherein the carbon dioxide inhibits production ofcarbon dioxide from the selected section.
 4794. The method of claim4793, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4795. The method of claim 4768, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.4796. The method of claim 4795, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4797. The method of claim 4768, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 4798. The method of claim 4768, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons aresubjected to a reaction within at least the portion of the selectedsection to increase a H₂ concentration within the produced synthesisgas.
 4799. The method of claim 4768, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin at least the portion of the selected section to increase anenergy content of the produced synthesis gas.
 4800. The method of claim4768, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4801. The method of claim4768, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4802. The method of claim 4768, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4803. The method of claim 4768, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heat sources.
 4804. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation such that the heat from the one or more heat sources pyrolyzesat least some of the hydrocarbons within the selected section of theformation; producing pyrolysis products from the formation; heating atleast a portion of the selected section to a temperature sufficient togenerate synthesis gas; controlling a temperature in or proximate to asynthesis gas production well to generate synthesis gas having aselected H₂ to CO ratio; providing a synthesis gas generating fluid toat least the portion of the selected section to generate synthesis gas;and producing synthesis gas from the formation.
 4805. The method ofclaim 4804, wherein the one or more heat sources comprise at least twoheat sources, and wherein superposition of heat from at least the twoheat sources pyrolyzes at least some hydrocarbons within the selectedsection of the formation.
 4806. The method of claim 4804, wherein theselected ratio is controlled to be approximately 2:1 H₂ to CO.
 4807. Themethod of claim 4804, wherein the selected ratio is controlled to rangefrom approximately 1.8:1 to approximately 2.2:1 H₂ to CO.
 4808. Themethod of claim 4804, wherein the selected ratio is controlled to beapproximately 3:1 H₂ to CO.
 4809. The method of claim 4804, wherein theselected ratio is controlled to range from approximately 2.8:1 toapproximately 3.2:1 H₂ to CO.
 4810. The method of claim 4804, furthercomprising providing at least a portion of the produced synthesis gas toa condensable hydrocarbon synthesis process to produce condensablehydrocarbons.
 4811. The method of claim 4810, wherein the condensablehydrocarbon synthesis process comprises a Fischer-Tropsch process. 4812.The method of claim 4811, further comprising cracking at least a portionof the condensable hydrocarbons to form middle distillates.
 4813. Themethod of claim 4804, further comprising providing at least a portion ofthe produced synthesis gas to a catalytic methanation process to producemethane.
 4814. The method of claim 4804, further comprising providing atleast a portion of the produced synthesis gas to a methanol-synthesisprocess to produce methanol.
 4815. The method of claim 4804, furthercomprising providing at least a portion of the produced synthesis gas toa gasoline-synthesis process to produce gasoline.
 4816. The method ofclaim 4804, further comprising allowing the heat to transfer from theone or more heat sources to the selected section to substantiallyuniformly increase a permeability of the selected section.
 4817. Themethod of claim 4804, further comprising controlling heat transfer fromthe one or more heat sources to produce a permeability within theselected section of greater than about 100 millidarcy.
 4818. The methodof claim 4804, further comprising heating at least the portion of theselected section when providing the synthesis gas generating fluid toinhibit temperature decrease within the selected section duringsynthesis gas generation.
 4819. The method of claim 4804, wherein thetemperature sufficient to allow synthesis gas generation is within arange from approximately 400° C. to approximately 1200° C.
 4820. Themethod of claim 4804, wherein heating at least the portion of theselected section to a temperature sufficient to allow synthesis gasgeneration comprises: heating zones adjacent to wellbores of one or moreheat sources with heaters disposed in the wellbores, wherein the heatersare configured to raise temperatures of the zones to temperaturessufficient to support reaction of carbon-containing material within thezones with an oxidizing fluid; introducing the oxidizing fluid to thezones substantially by diffusion; allowing the oxidizing fluid to reactwith at least a portion of the carbon-containing material within thezones to produce heat in the zones; and transferring heat from the zonesto the selected section.
 4821. The method of claim 4804, wherein heatingat least the portion of the selected section to a temperature sufficientto allow synthesis gas generation comprises: introducing an oxidizingfluid into the formation through a wellbore; transporting the oxidizingfluid substantially by convection into the portion of the selectedsection, wherein the portion of the selected section is at a temperaturesufficient to support an oxidization reaction with the oxidizing fluid;and reacting the oxidizing fluid within the portion of the selectedsection to generate heat and raise the temperature of the portion. 4822.The method of claim 4804, wherein the one or more heat sources compriseone or more electrical heaters disposed in the formation.
 4823. Themethod of claim 4804, wherein the one or more heat sources comprises oneor more natural distributor combustors.
 4824. The method of claim 4804,wherein the one or more heat sources comprise one or more heater wells,wherein at least one heater well comprises a conduit disposed within theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 4825. The method of claim 4804, whereinheating at least the portion of the selected section to a temperaturesufficient to allow synthesis gas generation and providing a synthesisgas generating fluid to at least the portion of the selected sectioncomprises introducing steam into the portion.
 4826. The method of claim4804, further comprising controlling the heating of at least the portionof selected section and provision of the synthesis gas generating fluidto maintain a temperature within at least the portion of the selectedsection above the temperature sufficient to generate synthesis gas.4827. The method of claim 4804, wherein the synthesis gas generatingfluid comprises liquid water.
 4828. The method of claim 4804, whereinthe synthesis gas generating fluid comprises steam.
 4829. The method ofclaim 4804, wherein the synthesis gas generating fluid comprises waterand carbon dioxide, wherein the carbon dioxide inhibits production ofcarbon dioxide from the selected section.
 4830. The method of claim4829, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4831. The method of claim 4804, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.4832. The method of claim 4831, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4833. The method of claim 4804, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 4834. The method of claim 4804, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons aresubjected to a reaction within at least the portion of the selectedsection to increase a H₂ concentration within the produced synthesisgas.
 4835. The method of claim 4804, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin at least the portion of the selected section to increase anenergy content of the produced synthesis gas.
 4836. The method of claim4804, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4837. The method of claim4804, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4838. The method of claim 4804, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4839. The method of claim 4804, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heat sources.
 4840. A method of treating a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a portion of the formation; allowing the heat totransfer from the one or more heat sources to a selected section of theformation such that the heat from the one or more heat sources pyrolyzesat least some of the hydrocarbons within the selected section of theformation; producing pyrolysis products from the formation; heating atleast a portion of the selected section to a temperature sufficient togenerate synthesis gas; controlling a temperature of at least a portionof the selected section to generate synthesis gas having a H₂ to COratio different than a selected H₂ to CO ratio; providing a synthesisgas generating fluid to at least the portion of the selected section togenerate synthesis gas; and producing synthesis gas from the formation;providing at least a portion of the produced synthesis gas to a shiftprocess wherein an amount of carbon monoxide is converted to carbondioxide; separating at least a portion of the carbon dioxide to obtain agas having a selected H₂ to CO ratio.
 4841. The method of claim 4840,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from at least the two heat sourcespyrolyzes at least some hydrocarbons within the selected section of theformation.
 4842. The method of claim 4840, wherein the selected ratio iscontrolled to be approximately 2:1 H₂ to CO.
 4843. The method of claim4840, wherein the selected ratio is controlled to range fromapproximately 1.8:1 to 2.2:1 H₂to CO.
 4844. The method of claim 4840,wherein the selected ratio is controlled to be approximately 3:1 H₂ toCO.
 4845. The method of claim 4840, wherein the selected ratio iscontrolled to range from approximately 2.8:1 to 3.2:1 H₂ to CO. 4846.The method of claim 4840, further comprising providing at least aportion of the produced synthesis gas to a condensable hydrocarbonsynthesis process to produce condensable hydrocarbons.
 4847. The methodof claim 4846, wherein the condensable hydrocarbon synthesis processcomprises a Fischer-Tropsch process.
 4848. The method of claim 4847,further comprising cracking at least a portion of the condensablehydrocarbons to form middle distillates.
 4849. The method of claim 4840,further comprising providing at least a portion of the producedsynthesis gas to a catalytic methanation process to produce methane.4850. The method of claim 4840, further comprising providing at least aportion of the produced synthesis gas to a methanol-synthesis process toproduce methanol.
 4851. The method of claim 4840, further comprisingproviding at least a portion of the produced synthesis gas to agasoline-synthesis process to produce gasoline.
 4852. The method ofclaim 4840, further comprising allowing the heat to transfer from theone or more heat sources to the selected section to substantiallyuniformly increase a permeability of the selected section.
 4853. Themethod of claim 4840, further comprising controlling heat transfer fromthe one or more heat sources to produce a permeability within theselected section of greater than about 100 millidarcy.
 4854. The methodof claim 4840, further comprising heating at least the portion of theselected section when providing the synthesis gas generating fluid toinhibit temperature decrease within the selected section duringsynthesis gas generation.
 4855. The method of claim 4840, wherein thetemperature sufficient to allow synthesis gas generation is within arange from approximately 400° C. to approximately 1200° C.
 4856. Themethod of claim 4840, wherein heating at least the portion of theselected section to a temperature sufficient to allow synthesis gasgeneration comprises: heating zones adjacent to wellbores of one or moreheat sources with heaters disposed in the wellbores, wherein the heatersare configured to raise temperatures of the zones to temperaturessufficient to support reaction of carbon-containing material within thezones with an oxidizing fluid; introducing the oxidizing fluid to thezones substantially by diffusion; allowing the oxidizing fluid to reactwith at least a portion of the carbon-containing material within thezones to produce heat in the zones; and transferring heat from the zonesto the selected section.
 4857. The method of claim 4840, wherein heatingat least the portion of the selected section to a temperature sufficientto allow synthesis gas generation comprises: introducing an oxidizingfluid into the formation through a wellbore; transporting the oxidizingfluid substantially by convection into the portion of the selectedsection, wherein the portion of the selected section is at a temperaturesufficient to support an oxidization reaction with the oxidizing fluid;and reacting the oxidizing fluid within the portion of the selectedsection to generate heat and raise the temperature of the portion. 4858.The method of claim 4840, wherein the one or more heat sources compriseone or more electrical heaters disposed in the formation.
 4859. Themethod of claim 4840, wherein the one or more heat sources comprises oneor more natural distributor combustors.
 4860. The method of claim 4840,wherein the one or more heat sources comprise one or more heater wells,wherein at least one heater well comprises a conduit disposed within theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 4861. The method of claim 4840, whereinheating at least the portion of the selected section to a temperaturesufficient to allow synthesis gas generation and providing a synthesisgas generating fluid to at least the portion of the selected sectioncomprises introducing steam into the portion.
 4862. The method of claim4840, further comprising controlling the heating of at least the portionof selected section and provision of the synthesis gas generating fluidto maintain a temperature within at least the portion of the selectedsection above the temperature sufficient to generate synthesis gas.4863. The method of claim 4840, wherein the synthesis gas generatingfluid comprises liquid water.
 4864. The method of claim 4840, whereinthe synthesis gas generating fluid comprises steam.
 4865. The method ofclaim 4840, wherein the synthesis gas generating fluid comprises waterand carbon dioxide, wherein the carbon dioxide inhibits production ofcarbon dioxide from the selected section.
 4866. The method of claim4865, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.4867. The method of claim 4840, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.4868. The method of claim 4867, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 4869. The method of claim 4840, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 4870. The method of claim 4840, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersless than 5, and wherein at least a portion of the hydrocarbons aresubjected to a reaction within at least the portion of the selectedsection to increase a H₂ concentration within the produced synthesisgas.
 4871. The method of claim 4840, wherein the synthesis gasgenerating fluid comprises water and hydrocarbons having carbon numbersgreater than 4, and wherein at least a portion of the hydrocarbons reactwithin at least the portion of the selected section to increase anenergy content of the produced synthesis gas.
 4872. The method of claim4840, further comprising maintaining a pressure within the formationduring synthesis gas generation, and passing produced synthesis gasthrough a turbine to generate electricity.
 4873. The method of claim4840, further comprising generating electricity from the synthesis gasusing a fuel cell.
 4874. The method of claim 4840, further comprisinggenerating electricity from the synthesis gas using a fuel cell,separating carbon dioxide from a fluid exiting the fuel cell, andstoring a portion of the separated carbon dioxide within a spent sectionof the formation.
 4875. The method of claim 4840, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heat sources.
 4876. A method of forming a spent portion offormation within a hydrocarbon containing formation, comprising: heatinga first portion of the formation to pyrolyze hydrocarbons within thefirst portion and to establish a substantially uniform permeabilitywithin the first portion; and cooling the first portion.
 4877. Themethod of claim 4876, wherein heating the first portion comprisestransferring heat to the first portion from one or more electricalheaters.
 4878. The method of claim 4876, wherein heating the firstportion comprises transferring heat to the first portion from one ormore natural distributor combustors.
 4879. The method of claim 4876,wherein heating the first portion comprises transferring heat to thefirst portion from one or more flameless distributor combustors. 4880.The method of claim 4876, wherein heating the first portion comprisestransferring heat to the first portion from heat transfer fluid flowingwithin one or more wellbores within the formation.
 4881. The method ofclaim 4880, wherein the heat transfer fluid comprises steam.
 4882. Themethod of claim 4880, wherein the heat transfer fluid comprisescombustion products from a burner.
 4883. The method of claim 4876,wherein heating the first portion comprises transferring heat to thefirst portion from at least two heater wells positioned within theformation, wherein the at least two heater wells are placed in asubstantially regular pattern, wherein the substantially regular patterncomprises repetition of a base heater unit, and wherein the base heaterunit is formed of a number of heater wells.
 4884. The method of claim4883, wherein a spacing between a pair of adjacent heater wells iswithin a range from about 6 m to about 15 m.
 4885. The method of claim4883, further comprising removing fluid from the formation through oneor more production wells.
 4886. The method of claim 4885, wherein theone or more production wells are located in a pattern, and wherein theone or more production wells are positioned substantially at centers ofbase heater units.
 4887. The method of claim 4883, wherein the heaterunit comprises three heater wells positioned substantially at apexes ofan equilateral triangle.
 4888. The method of claim 4883, wherein theheater unit comprises four heater wells positioned substantially atapexes of a rectangle.
 4889. The method of claim 4883, wherein theheater unit comprises five heater wells positioned substantially atapexes of a regular pentagon.
 4890. The method of claim 4883, whereinthe heater unit comprises six heater wells positioned substantially atapexes of a regular hexagon.
 4891. The method of claim 4876, furthercomprising introducing water to the first portion to cool the formation.4892. The method of claim 4876, further comprising removing steam fromthe formation.
 4893. The method of claim 4892, further comprising usinga portion of the removed steam to heat a second portion of theformation.
 4894. The method of claim 4876, further comprising removingpyrolyzation products from the formation.
 4895. The method of claim4876, further comprising generating synthesis gas within the portion byintroducing a synthesis gas generating fluid into the portion, andremoving synthesis gas from the formation.
 4896. The method of claim4876, further comprising heating a second section of the formation topyrolyze hydrocarbons within the second portion, removing pyrolyzationfluid from the second portion, and storing a portion of the removedpyrolyzation fluid within the first portion.
 4897. The method of claim4896, wherein the portion of the removed pyrolyzation fluid is storedwithin the first portion when surface facilities that process theremoved pyrolyzation fluid are not able to process the portion of theremoved pyrolyzation fluid.
 4898. The method of claim 4896, furthercomprising heating the first portion to facilitate removal of the storedpyrolyzation fluid from the first portion.
 4899. The method of claim4876, further comprising generating synthesis gas within a secondportion of the formation, removing synthesis gas from the secondportion, and storing a portion of the removed synthesis gas within thefirst portion.
 4900. The method of claim 4899, wherein the portion ofthe removed synthesis gas from the second portion are stored within thefirst portion when surface facilities that process the removed synthesisgas are not able to process the portion of the removed synthesis gas.4901. The method of claim 4899, further comprising heating the firstportion to facilitate removal of the stored synthesis gas from the firstportion.
 4902. The method of claim 4876, further comprising removing atleast a portion of carbon containing material in the first portion and,further comprising using at least a portion of the carbon containingmaterial removed from the formation in a metallurgical application.4903. The method of claim 4902, wherein the metallurgical applicationcomprises steel manufacturing.
 4904. A method of sequestering carbondioxide within a hydrocarbon containing formation, comprising: heating aportion of the formation to increase permeability and form asubstantially uniform permeability within the portion; allowing theportion to cool; and storing carbon dioxide within the portion. 4905.The method of claim 4904, wherein the permeability of the portion isincreased to over 100 millidarcy.
 4906. The method of claim 4904,further comprising raising a water level within the portion to inhibitmigration of the carbon dioxide from the portion.
 4907. The method ofclaim 4904, further comprising heating the portion to release carbondioxide, and removing carbon dioxide from the portion.
 4908. The methodof claim 4904, further comprising pyrolyzing hydrocarbons within theportion during heating of the portion, and removing pyrolyzation productfrom the formation.
 4909. The method of claim 4904, further comprisingproducing synthesis gas from the portion during the heating of theportion, and removing synthesis gas from the formation.
 4910. The methodof claim 4904, wherein heating the portion comprises: heating carboncontaining material adjacent to one or more wellbores to a temperaturesufficient to support oxidation of the carbon containing material withan oxidizing fluid; introducing the oxidizing fluid to carbon containingmaterial adjacent to the one or more wellbores to oxidize thehydrocarbons and produce heat; and conveying produced heat to theportion.
 4911. The method of claim 4910, wherein heating carboncontaining material adjacent to the one or more wells compriseselectrically heating the carbon containing material.
 4912. The method ofclaim 4910, wherein the temperature sufficient to support oxidation isin a range between approximately 200° C. to approximately 1200° C. 4913.The method of claim 4904, wherein heating the portion comprisescirculating heat transfer fluid through one or more heating wells withinthe formation.
 4914. The method of claim 4913, wherein the heat transferfluid comprises combustion products from a burner.
 4915. The method ofclaim 4913, wherein the heat transfer fluid comprises steam.
 4916. Themethod of claim 4904, further comprising removing fluid from theformation during heating of the formation, and combusting a portion ofthe removed fluid to generate heat to heat the formation.
 4917. Themethod of claim 4904, further comprising using at least a portion of thecarbon dioxide for hydrocarbon bed demethanation prior to storing thecarbon dioxide within the portion.
 4918. The method of claim 4904,further comprising using a portion of the carbon dioxide for enhancedoil recovery prior to storing the carbon dioxide within the portion.4919. The method of claim 4904, wherein at least a portion of the carbondioxide comprises carbon dioxide generated in a fuel cell.
 4920. Themethod of claim 4904, wherein at least a portion of the carbon dioxidecomprises carbon dioxide formed as a combustion product.
 4921. Themethod of claim 4904, further comprising allowing the portion to cool byintroducing water to the portion; and removing the water from theformation as steam.
 4922. The method of claim 4921, further comprisingusing the steam as a heat transfer fluid to heat a second portion of theformation.
 4923. The method of claim 4904, wherein storing carbondioxide in the portion comprises adsorbing carbon dioxide to carboncontaining material within the formation.
 4924. The method of claim4904, wherein storing carbon dioxide comprises passing a first fluidstream comprising the carbon dioxide and other fluid through theportion; adsorbing carbon dioxide onto carbon containing material withinthe formation; and removing a second fluid stream from the formation,wherein a concentration of the other fluid in the second fluid stream isgreater than concentration of other fluid in the first stream due to theabsence of the adsorbed carbon dioxide in the second stream.
 4925. Themethod of claim 4904, wherein an amount of carbon dioxide stored withinthe portion is equal to or greater than an amount of carbon dioxidegenerated within the portion and removed from the formation duringheating of the portion.
 4926. The method of claim 4904, furthercomprising providing heat from three or more heat sources to at least aportion of the formation, wherein three or more of the heat sources arelocated in the formation in a unit of heat sources, and wherein the unitof heat sources comprises a triangular pattern.
 4927. The method ofclaim 4904, further comprising providing heat from three or more heatsources to at least a portion of the formation, wherein three or more ofthe heat sources are located in the formation in a unit of heat sources,wherein the unit of heat sources comprises a triangular pattern, andwherein a plurality of the units are repeated over an area of theformation to form a repetitive pattern of units.
 4928. A method of insitu sequestration of carbon dioxide within a hydrocarbon containingformation in situ, comprising: providing heat from one or more heatsources to at least a first portion of the formation; allowing the heatto transfer from one or more sources to a selected section of theformation such that the heat from the one or more heat sources pyrolyzesat least some of the hydrocarbons within the selected section of theformation; producing pyrolyzation fluids, wherein the pyrolyzationfluids comprise carbon dioxide; and storing an amount of carbon dioxidein the formation, wherein the amount of stored carbon dioxide is equalto or greater than an amount of carbon dioxide within the pyrolyzationfluids.
 4929. The method of claim 4928, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 4930. Themethod of claim 4928, wherein the carbon dioxide is stored within aspent portion of the formation.
 4931. The method of claim 4928, whereina portion of the carbon dioxide stored within the formation is carbondioxide separated from the pyrolyzation fluids.
 4932. The method ofclaim 4928, further comprising separating a portion of carbon dioxidefrom the pyrolyzation fluids, and using the carbon dioxide as a floodingagent in enhanced oil recovery.
 4933. The method of claim 4928, furthercomprising separating a portion of carbon dioxide from the pyrolyzationfluids, and using the carbon dioxide as a synthesis gas generating fluidfor the generation of synthesis gas from a section of the formation thatis heated to a temperature sufficient to generate synthesis gas uponintroduction of the synthesis gas generating fluid.
 4934. The method ofclaim 4928, further comprising separating a portion of carbon dioxidefrom the pyrolyzation fluids, and using the carbon dioxide to displacehydrocarbon bed methane.
 4935. The method of claim 4934, wherein thehydrocarbon bed is a deep hydrocarbon bed located over 760 m belowground surface.
 4936. The method of claim 4934, further comprisingadsorbing a portion of the carbon dioxide within the hydrocarbon bed.4937. The method of claim 4928, further comprising using at least aportion of the pyrolyzation fluids as a feed stream for a fuel cell.4938. The method of claim 4937, wherein the fuel cell generates carbondioxide, and further comprising storing an amount of carbon dioxideequal to or greater than an amount of carbon dioxide generated by thefuel cell within the formation.
 4939. The method of claim 4928, whereina spent portion of the formation comprises carbon containing materialwithin a section of the formation that has been heated and from whichcondensable hydrocarbons have been produced, and wherein the spentportion of the formation is at a temperature at which carbon dioxideadsorbs onto the carbon containing material.
 4940. The method of claim4928, further comprising raising a water level within the spent portionto inhibit migration of the carbon dioxide from the portion.
 4941. Themethod of claim 4928, wherein producing fluids from the formationcomprises removing pyrolyzation products from the formation.
 4942. Themethod of claim 4928, wherein producing fluids from the formationcomprises heating the selected section to a temperature sufficient togenerate synthesis gas; introducing a synthesis gas generating fluidinto the selected section; and removing synthesis gas from theformation.
 4943. The method of claim 4942, wherein the temperaturesufficient to generate synthesis gas ranges from about 400° C. to about1200° C.
 4944. The method of claim 4942, wherein heating the selectedsection comprises introducing an oxidizing fluid into the selectedsection, reacting the oxidizing fluid within the selected section toheat the selected section.
 4945. The method of claim 4942, whereinheating the selected section comprises: heating carbon containingmaterial adjacent to one or more wellbores to a temperature sufficientto support oxidation of the carbon containing material with an oxidant;introducing the oxidant to carbon containing material adjacent to theone or more wellbores to oxidize the hydrocarbons and produce heat; andconveying produced heat to the portion.
 4946. The method of claim 4928,wherein the spent portion of the formation comprises a substantiallyuniform permeability created by heating the spent formation and removingfluid during formation of the spent portion.
 4947. The method of claim4928, wherein the one or more heat sources comprise electrical heaters.4948. The method of claim 4928, wherein the one or more heat sourcescomprise flameless distributor combustors.
 4949. The method of claim4948, wherein a portion of fuel for the one or more flamelessdistributor combustors is obtained from the formation.
 4950. The methodof claim 4928, wherein the one or more heat sources comprise heaterwells in the formation through which heat transfer fluid is circulated.4951. The method of claim 4950, wherein the heat transfer fluidcomprises combustion products.
 4952. The method of claim 4950, whereinthe heat transfer fluid comprises steam.
 4953. The method of claim 4928,wherein condensable hydrocarbons are produced under pressure, andfurther comprising generating electricity by passing a portion of theproduced fluids through a turbine.
 4954. The method of claim 4928,further comprising providing heat from three or more heat sources to atleast a portion of the formation, wherein three or more of the heatsources are located in the formation in a unit of heat sources, andwherein the unit of heat sources comprises a triangular pattern. 4955.The method of claim 4928, further comprising providing heat from threeor more heat sources to at least a portion of the formation, whereinthree or more of the heat sources are located in the formation in a unitof heat sources, wherein the unit of heat sources comprises a triangularpattern, and wherein a plurality of the units are repeated over an areaof the formation to form a repetitive pattern of units.
 4956. A methodfor in situ production of energy from a hydrocarbon containingformation, comprising: providing heat from one or more heat sources toat least a portion of the formation; allowing the heat to transfer fromthe one or more heat sources to a selected section of the formation suchthat the heat from the one or more heat sources pyrolyzes at least aportion of the hydrocarbons within the selected section of theformation; producing pyrolysis products from the formation; providing atleast a portion of the pyrolysis products to a reformer to generatesynthesis gas; producing the synthesis gas from the reformer; providingat least a portion of the produced synthesis gas to a fuel cell toproduce electricity, wherein the fuel cell produces a carbon dioxidecontaining exit stream; and storing at least a portion of the carbondioxide in the carbon dioxide containing exit stream in a subsurfaceformation.
 4957. The method of claim 4956, wherein the one or more heatsources comprise at least two heat sources, and wherein superposition ofheat from at least the two heat sources pyrolyzes at least somehydrocarbons within the selected section of the formation.
 4958. Themethod of claim 4956, wherein at least a portion of the pyrolysisproducts are used as fuel in the reformer.
 4959. The method of claim4956, wherein the synthesis gas comprises substantially of H₂.
 4960. Themethod of claim 4956, wherein the subsurface formation is a spentportion of the formation.
 4961. The method of claim 4956, wherein thesubsurface formation is an oil reservoir.
 4962. The method of claim4961, wherein at least a portion of the carbon dioxide is used as adrive fluid for enhanced oil recovery in the oil reservoir.
 4963. Themethod of claim 4956, wherein the subsurface formation is a hydrocarbonformation.
 4964. The method of claim 4956, wherein at least a portion ofthe carbon dioxide is used to produce methane from the hydrocarbonformation.
 4965. The method of claim 4963, wherein the coal formation islocated over about 760 m below ground surface.
 4966. The method of claim4964, further comprising sequestering at least a portion of the carbondioxide within the hydrocarbon formation.
 4967. The method of claim4956, wherein the reformer produces a reformer carbon dioxide containingexit stream.
 4968. The method of claim 4966, further comprising storingat least a portion of the carbon dioxide in the reformer carbon dioxidecontaining exit stream in the subsurface formation.
 4969. The method ofclaim 4968, wherein the subsurface formation is a spent portion of theformation.
 4970. The method of claim 4968, wherein the subsurfaceformation is an oil reservoir.
 4971. The method of claim 4970, whereinat least a portion of the carbon dioxide in the reformer carbon dioxidecontaining exit stream is used as a drive fluid for enhanced oilrecovery in the oil reservoir.
 4972. The method of claim 4968, whereinthe subsurface formation is a hydrocarbon formation.
 4973. The method ofclaim 4872, wherein at least a portion of the carbon dioxide in thereformer carbon dioxide containing exit stream is used to producemethane from the hydrocarbon formation.
 4974. The method of claim 4972,wherein the hydrocarbon formation is located over about 760 m belowground surface.
 4975. The method of claim 4973, further comprisingsequestering at least a portion of the carbon dioxide in the reformercarbon dioxide containing exit stream within the hydrocarbon formation.4976. The method of claim 4956, wherein the fuel cell is a moltencarbonate fuel cell.
 4977. The method of claim 4956, wherein the fuelcell is a solid oxide fuel cell.
 4978. The method of claim 4956, furthercomprising using a portion of the produced electricity to powerelectrical heaters within the formation.
 4979. The method of claim 4956,further comprising using a portion of the produced pyrolysis products asa feed stream for the fuel cell.
 4980. The method of claim 4956, whereinthe one or more heat sources comprise one or more electrical heatersdisposed in the formation.
 4981. The method of claim 4956, wherein theone or more heat sources comprise one or more flameless distributorcombustors disposed in the formation.
 4982. The method of claim 4981,wherein a portion of fuel for the flameless distributor combustors isobtained from the formation.
 4983. The method of claim 4956, wherein theone or more heat sources comprise one or more heater wells, wherein atleast one heater well comprises a conduit disposed within the formation,and further comprising heating the conduit by flowing a hot fluidthrough the conduit.
 4984. The method of claim 4956, further comprisingusing a portion of the synthesis gas as a combustion fuel for the one ormore heat sources.
 4985. A method for producing ammonia using a carboncontaining formation, comprising: separating air to produce an O₂ richstream and a N₂ rich stream; heating a selected section of the formationto a temperature sufficient to support reaction of carbon-containingmaterial in the formation to form synthesis gas; providing synthesis gasgenerating fluid and at least a portion of the O₂ rich stream to theselected section; allowing the synthesis gas generating fluid and O₂ inthe O₂ rich stream to react with at least a portion of thecarbon-containing material in the formation to generate synthesis gas;producing synthesis gas from the formation, wherein the synthesis gascomprises H₂ and CO; providing at least a portion of the H₂ in thesynthesis gas to an ammonia synthesis process; providing N₂ to theammonia synthesis process; and using the ammonia synthesis process togenerate ammonia.
 4986. The method of claim 4985, wherein the ratio ofthe H₂ to N₂ provided to the ammonia synthesis process is approximately3:1.
 4987. The method of claim 4985, wherein the ratio of the H₂ to N₂provided to the ammonia synthesis process ranges from approximately2.8:1 to approximately 3.2:1.
 4988. The method of claim 4985, whereinthe temperature sufficient to support reaction of carbon-containingmaterial in the formation to form synthesis gas ranges fromapproximately 400° C. to approximately 1200° C.
 4989. The method ofclaim 4985, further comprising separating at least a portion of carbondioxide in the synthesis gas from at least a portion of the synthesisgas.
 4990. The method of claim 4989, wherein the carbon dioxide isseparated from the synthesis gas by an amine separator.
 4991. The methodof claim 4990, further comprising providing at least a portion of thecarbon dioxide to a urea synthesis process to produce urea.
 4992. Themethod of claim 4985, wherein at least a portion of the N₂ stream isused to condense hydrocarbons with 4 or more carbon atoms from apyrolyzation fluid.
 4993. The method of claim 4985, wherein at least aportion of the N₂ rich stream is provided to the ammonia synthesisprocess.
 4994. The method of claim 4985, wherein the air is separated bycryogenic distillation.
 4995. The method of claim 4985, wherein the airis separated by membrane separation.
 4996. The method of claim 4985,wherein fluids produced during pyrolysis of a hydrocarbon containingformation comprise ammonia and, further comprising adding at least aportion of such ammonia to the ammonia generated from the ammoniasynthesis process.
 4997. The method of claim 4985, wherein fluidsproduced during pyrolysis of a hydrocarbon formation are hydrotreatedand at least some ammonia is produced during hydrotreating, and, furthercomprising adding at least a portion of such ammonia to the ammoniagenerated from the ammonia synthesis process.
 4998. The method of claim4985, further comprising providing at least a portion of the ammonia toa urea synthesis process to produce urea.
 4999. The method of claim4985, further comprising providing at least a portion of the ammonia toa urea synthesis process to produce urea and, further comprisingproviding carbon dioxide from the formation to the urea synthesisprocess.
 5000. The method of claim 4985, further comprising providing atleast a portion of the ammonia to a urea synthesis process to produceurea and, further comprising shifting at least a portion of the carbonmonoxide to carbon dioxide in a shift process, and further comprisingproviding at least a portion of the carbon dioxide from the shiftprocess to the urea synthesis process.
 5001. The method of claim 4985,wherein heating the selected section of the formation to a temperatureto support reaction of carbon containing material in the formation toform synthesis gas comprises: heating zones adjacent to wellbores of oneor more heat sources with heaters disposed in the wellbores, wherein theheaters are configured to raise temperatures of the zones totemperatures sufficient to support reaction of carbon-containingmaterial within the zones with O₂ in the O₂ rich stream; introducing theO₂ to the zones substantially by diffusion; allowing O₂ in the O₂ richstream to react with at least a portion of the carbon-containingmaterial within the zones to produce heat in the zones; and transferringheat from the zones to the selected section.
 5002. The method of claim5001, wherein temperatures sufficient to support reaction ofcarbon-containing material within the zones with O₂ range fromapproximately 200° C. to approximately 1200° C.
 5003. The method ofclaim 5001, wherein the one or more heat sources comprises one or moreelectrical heaters disposed in the formation.
 5004. The method of claim5001, wherein the one or more heat sources comprises one or more naturaldistributor combustors.
 5005. The method of claim 5001, wherein the oneor more heat sources comprise one or more heater wells, wherein at leastone heater well comprises a conduit disposed within the formation, andfurther comprising heating the conduit by flowing a hot fluid throughthe conduit.
 5006. The method of claim 5001, further comprising using aportion of the synthesis gas as a combustion fuel for the one or moreheat sources.
 5007. The method of claim 4985, wherein heating theselected section of the formation to a temperature to support reactionof carbon containing material in the formation to form synthesis gascomprises: introducing the O₂ rich stream into the formation through awellbore; transporting O₂ in the O₂ rich stream substantially byconvection into the portion of the selected section, wherein the portionof the selected section is at a temperature sufficient to support anoxidization reaction with O₂ in the O₂ rich stream; and reacting the O₂within the portion of the selected section to generate heat and raisethe temperature of the portion.
 5008. The method of claim 5008, whereinthe temperature sufficient to support an oxidization reaction with O₂ranges from approximately 200° C. to approximately 1200° C.
 5009. Themethod of claim 5008, wherein the one or more heat sources comprises oneor more electrical heaters disposed in the formation.
 5010. The methodof claim 5008, wherein the one or more heat sources comprises one ormore natural distributor combustors.
 5011. The method of claim 5008,wherein the one or more heat sources comprise one or more heater wells,wherein at least one heater well comprises a conduit disposed within theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 5012. The method of claim 5008, furthercomprising using a portion of the synthesis gas as a combustion fuel forthe one or more heat sources.
 5013. The method of claim 4985, furthercomprising controlling the heating of at least the portion of theselected section and provision of the synthesis gas generating fluid tomaintain a temperature within at least the portion of the selectedsection above the temperature sufficient to generate synthesis gas.5014. The method of claim 4985, wherein the synthesis gas generatingfluid comprises liquid water.
 5015. The method of claim 4985, whereinthe synthesis gas generating fluid comprises steam.
 5016. The method ofclaim 4985, wherein the synthesis gas generating fluid comprises waterand carbon dioxide wherein the carbon dioxide inhibits production ofcarbon dioxide from the selected section.
 5017. The method of claim5016, wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.5018. The method of claim 4985, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.5019. The method of claim 5018, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 5020. The method of claim 4985, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 5021. A method for producing ammonia using a carbon containingformation, comprising: generating a first ammonia feed stream from afirst portion of the formation; generating a second ammonia feed streamfrom a second portion of the formation, wherein the second ammonia feedstream has a H₂ to N₂ ratio greater than a H₂ to N₂ ratio of the firstammonia feed stream; blending at least a portion of the first ammoniafeed stream with at least a portion of the second ammonia feed stream toproduce a blended ammonia feed stream having a selected H₂ to N₂ ratio;providing the blended ammonia feed stream to an ammonia synthesisprocess; and using the ammonia synthesis process to generate ammonia.5022. The method of claim 5021, wherein the selected ratio isapproximately 3:1.
 5023. The method of claim 5021, wherein the selectedratio ranges from approximately 2.8:1 to approximately 3.2:1.
 5024. Themethod of claim 5021, further comprising separating at least a portionof carbon dioxide in the first ammonia feed stream from at least aportion of the first ammonia feed stream.
 5025. The method of claim5024, wherein the carbon dioxide is separated from the first ammoniafeed stream by an amine separator.
 5026. The method of claim 5025,further comprising providing at least a portion of the carbon dioxide toa urea synthesis process.
 5027. The method of claim 5021, furthercomprising separating at least a portion of carbon dioxide in theblended ammonia feed stream from at least a portion of the blendedammonia feed stream.
 5028. The method of claim 5027, wherein the carbondioxide is separated from the blended ammonia feed stream by an amineseparator.
 5029. The method of claim 5028, further comprising providingat least a portion of the carbon dioxide to a urea synthesis process5030. The method of claim 5021, further comprising separating at least aportion of carbon dioxide in the second ammonia feed stream from atleast a portion of the second ammonia feed stream.
 5031. The method ofclaim 5030, wherein the carbon dioxide is separated from the secondammonia feed stream by an amine separator.
 5032. The method of claim5031, further comprising providing at least a portion of the carbondioxide to a urea synthesis process.
 5033. The method of claim 5021,wherein fluids produced during pyrolysis of a hydrocarbon containingformation comprise ammonia and, further comprising adding at least aportion of such ammonia to the ammonia generated from the ammoniasynthesis process.
 5034. The method of claim 5021, wherein fluidsproduced during pyrolysis of a hydrocarbon formation are hydrotreatedand at least some ammonia is produced during hydrotreating, and furthercomprising adding at least a portion of such ammonia to the ammoniagenerated from the ammonia synthesis process.
 5035. The method of claim5021, further comprising providing at least a portion of the ammonia toa urea synthesis process to produce urea.
 5036. The method of claim5021, further comprising providing at least a portion of the ammonia toa urea synthesis process to produce urea and, further comprisingproviding carbon dioxide from the formation to the urea synthesisprocess.
 5037. The method of claim 5021, further comprising providing atleast a portion of the ammonia to a urea synthesis process to produceurea and further comprising shifting at least a portion of carbonmonoxide in the blended ammonia feed stream to carbon dioxide in a shiftprocess, and further comprising providing at least a portion of thecarbon dioxide from the shift process to the urea synthesis process.5038. A method for producing ammonia using a carbon containingformation, comprising: heating a selected section of the formation to atemperature sufficient to support reaction of carbon-containing materialin the formation to form synthesis gas; providing a synthesis gasgenerating fluid and an O₂ rich stream to the selected section, whereinthe amount of N₂ in the O₂ rich stream is sufficient to generatesynthesis gas having a selected ratio of H₂ to N₂; allowing thesynthesis gas generating fluid and O₂ in the O₂ rich stream to reactwith at least a portion of the carbon-containing material in theformation to generate synthesis gas having a selected ratio of H₂ to N₂;producing the synthesis gas from the formation; providing at least aportion of the H₂ and N₂ in the synthesis gas to an ammonia synthesisprocess; using the ammonia synthesis process to generate ammonia. 5039.The method of claim 5038, further comprising controlling a temperatureof at least a portion of the selected section to generate synthesis gashaving the selected H₂ to N₂ ratio.
 5040. The method of claim 5038,wherein the selected ratio is approximately 3:1.
 5041. The method ofclaim 5038, wherein the selected ratio ranges from approximately 2.8:1to 3.2:1.
 5042. The method of claim 5038, wherein the temperaturesufficient to support reaction of carbon-containing material in theformation to form synthesis gas ranges from approximately 400° C. toapproximately 1200° C.
 5043. The method of claim 5038, wherein the O₂stream and N₂ stream are obtained by cryogenic separation of air. 5044.The method of claim 5038, wherein the O₂ stream and N₂ stream areobtained by membrane separation of air.
 5045. The method of claim 5038,further comprising separating at least a portion of carbon dioxide inthe synthesis gas from at least a portion of the synthesis gas. 5046.The method of claim 5045, wherein the carbon dioxide is separated fromthe synthesis gas by an amine separator.
 5047. The method of claim 5046,further comprising providing at least a portion of the carbon dioxide toa urea synthesis process.
 5048. The method of claim 5038, wherein fluidsproduced during pyrolysis of a hydrocarbon containing formation compriseammonia and, further comprising adding at least a portion of suchammonia to the ammonia generated from the ammonia synthesis process.5049. The method of claim 5038, wherein fluids produced during pyrolysisof a hydrocarbon formation are hydrotreated and at least some ammonia isproduced during hydrotreating, and further comprising adding at least aportion of such ammonia to the ammonia generated from the ammoniasynthesis process.
 5050. The method of claim 5038, further comprisingproviding at least a portion of the ammonia to a urea synthesis processto produce urea.
 5051. The method of claim 5038, further comprisingproviding at least a portion of the ammonia to a urea synthesis processto produce urea and, further comprising providing carbon dioxide fromthe formation to the urea synthesis process.
 5052. The method of claim5038, further comprising providing at least a portion of the ammonia toa urea synthesis process to produce urea and further comprising shiftingat least a portion of carbon monoxide in the synthesis gas to carbondioxide in a shift process, and further comprising providing at least aportion of the carbon dioxide from the shift process to the ureasynthesis process.
 5053. The method of claim 5038, where in heating aselected section of the formation to a temperature to support reactionof carbon containing material in the formation to form synthesis gascomprises: heating zones adjacent to wellbores of one or more heatsources with heaters disposed in the wellbores, wherein the heaters areconfigured to raise temperatures of the zones to temperatures sufficientto support reaction of carbon-containing material within the zones withO₂ in the O₂ rich stream; introducing the O₂ to the zones substantiallyby diffusion; allowing O₂ in the O₂ rich stream to react with at least aportion of the carbon-containing material within the zones to produceheat in the zones; and transferring heat from the zones to the selectedsection.
 5054. The method of claim 5053, wherein temperatures sufficientto support reaction of carbon-containing material within the zones withO₂ range from approximately 200° C. to approximately 1200° C.
 5055. Themethod of claim 5053, wherein the one or more heat sources comprises oneor more electrical heaters disposed in the formation.
 5056. The methodof claim 5053, wherein the one or more heat sources comprises one ormore natural distributor combustors.
 5057. The method of claim 5053,wherein the one or more heat sources comprise one or more heater wells,wherein at least one heater well comprises a conduit disposed within theformation, and further comprising heating the conduit by flowing a hotfluid through the conduit.
 5058. The method of claim 5053, furthercomprising using a portion of the synthesis gas as a combustion fuel forthe one or more heat sources.
 5059. The method of claim 5038, whereinheating the selected section of the formation to a temperature tosupport reaction of carbon containing material in the formation to formsynthesis gas comprises: introducing the O₂ rich stream into theformation through a wellbore; transporting O₂ in the O₂ rich streamsubstantially by convection into the portion of the selected section,wherein the portion of the selected section is at a temperaturesufficient to support an oxidization reaction with O₂ in the O₂ richstream; and reacting the O₂ within the portion of the selected sectionto generate heat and raise the temperature of the portion.
 5060. Themethod of claim 5059, wherein the temperature sufficient to support anoxidization reaction with O₂ ranges from approximately 200° C. toapproximately 1200° C.
 5061. The method of claim 5059, wherein the oneor more heat sources comprises one or more electrical heaters disposedin the formation.
 5062. The method of claim 5059, wherein the one ormore heat sources comprises one or more natural distributor combustors.5063. The method of claim 5059, wherein the one or more heat sourcescomprise one or more heater wells, wherein at least one heater wellcomprises a conduit disposed within the formation, and furthercomprising heating the conduit by flowing a hot fluid through theconduit.
 5064. The method of claim 5059, further comprising using aportion of the synthesis gas as a combustion fuel for the one or moreheat sources.
 5065. The method of claim 5038, further comprisingcontrolling the heating of at least the portion of the selected sectionand provision of the synthesis gas generating fluid to maintain atemperature within at least the portion of the selected section abovethe temperature sufficient to generate synthesis gas.
 5066. The methodof claim 5038, wherein the synthesis gas generating fluid comprisesliquid water.
 5067. The method of claim 5038, wherein the synthesis gasgenerating fluid comprises steam.
 5068. The method of claim 5038,wherein the synthesis gas generating fluid comprises water and carbondioxide, wherein the carbon dioxide inhibits production of carbondioxide from the selected section.
 5069. The method of claim 5068,wherein a portion of the carbon dioxide within the synthesis gasgenerating fluid comprises carbon dioxide removed from the formation.5070. The method of claim 5038, wherein the synthesis gas generatingfluid comprises carbon dioxide, and wherein a portion of the carbondioxide reacts with carbon in the formation to generate carbon monoxide.5071. The method of claim 5070, wherein a portion of the carbon dioxidewithin the synthesis gas generating fluid comprises carbon dioxideremoved from the formation.
 5072. The method of claim 5038, whereinproviding the synthesis gas generating fluid to at least the portion ofthe selected section comprises raising a water table of the formation toallow water to flow into the at least the portion of the selectedsection.
 5073. A method for producing ammonia using a carbon containingformation, comprising: providing a first stream comprising N₂ and carbondioxide to the formation; allowing at least a portion of the carbondioxide in the first stream to adsorb in the formation; producing asecond stream from the formation, wherein the second stream comprises alower percentage of carbon dioxide than the first stream; providing atleast a portion of the N₂ in the second stream to an ammonia synthesisprocess.
 5074. The method of claim 5073, wherein the second streamcomprises H₂ from the formation.
 5075. The method of claim 5073, whereinthe first stream is produced from a carbon containing formation. 5076.The method of claim 5075, wherein the first stream is generated byreacting a oxidizing fluid with carbon containing material in theformation.
 5077. The method of claim 5073, wherein the second streamcomprises H₂ from the formation and, further comprising providing suchH₂ to the ammonia synthesis process.
 5078. The method of claim 5073,further comprising using the ammonia synthesis process to generateammonia.
 5079. The method of claim 5078, wherein fluids produced duringpyrolysis of a hydrocarbon containing formation comprise ammonia and,further comprising adding at least a portion of such ammonia to theammonia generated from the ammonia synthesis process.
 5080. The methodof claim 5078, wherein fluids produced during pyrolysis of a hydrocarbonformation are hydrotreated and at least some ammonia is produced duringhydrotreating, and further comprising adding at least a portion of suchammonia to the ammonia generated from the ammonia synthesis process.5081. The method of claim 5078, further comprising providing at least aportion of the ammonia to a urea synthesis process to produce urea.5082. The method of claim 5078, further comprising providing at least aportion of the ammonia to a urea synthesis process to produce urea and,further comprising providing carbon dioxide from the formation to theurea synthesis process.
 5083. The method of claim 5078, furthercomprising providing at least a portion of the ammonia to a ureasynthesis process to produce urea and further comprising shifting atleast a portion of carbon monoxide in the synthesis gas to carbondioxide in a shift process, and further comprising providing at least aportion of the carbon dioxide from the shift process to the ureasynthesis process.
 5084. A method of treating a hydrocarbon containingpermeable formation in situ, comprising: providing heat from one or moreheat sources to at least one portion of the permeable formation;allowing the heat to transfer from the one or more heat sources to aselected mobilization section of the permeable formation such that theheat from the one or more heat sources can mobilize at least some of thehydrocarbons within the selected mobilization section of the permeableformation; controlling the heat from the one or more heat sources suchthat an average temperature within at least a majority of the selectedmobilization section of the permeable formation is less than about 150°C.; allowing the heat to transfer from the one or more heat sources to aselected pyrolyzation section of the permeable formation such that theheat from the one or more heat sources can pyrolyze at least some of thehydrocarbons within the selected pyrolyzation section of the permeableformation; controlling the heat from the one or more heat sources suchthat an average temperature within at least a majority of the selectedpyrolyzation section of the permeable formation is less than about 375°C.; and producing a mixture from the permeable formation.
 5085. Themethod of claim 5084, wherein the one or more heat sources comprise atleast two heat sources, and wherein superposition of heat from the oneor more heat sources can mobilize at least some of the hydrocarbonswithin the selected mobilization section of the permeable formation.5086. The method of claim 5084, wherein the one or more heat sourcescomprise at least two heat sources, and wherein superposition of heatfrom the one or more heat sources can mobilize at least some of thehydrocarbons within the selected pyrolyzation section of the permeableformation.
 5087. The method of claim 5084, wherein the one or more heatsources comprise electrical heaters.
 5088. The method of claim 5084,wherein the one or more heat sources comprise surface burners.
 5089. Themethod of claim 5084, wherein the one or more heat sources compriseflameless distributed combustors.
 5090. The method of claim 5084,wherein the one or more heat sources comprise natural distributedcombustors.
 5091. The method of claim 5084, further comprising disposingthe one or more heat sources horizontally within the permeableformation.
 5092. The method of claim 5084, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe permeable formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 5093. The method of claim 5084, further comprisingcontrolling the heat such that an average heating rate of the selectedpyrolyzation section is less than about 15° C./day during pyrolysis.5094. The method of claim 5084, wherein providing heat from the one ormore heat sources to at least the portion of permeable formationcomprises: heating a selected volume (V) of the hydrocarbon containingpermeable formation from the one or more heat sources, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 5095. Themethod of claim 5084, wherein allowing the heat to transfer from the oneor more heat sources to the selected mobilization section and/or theselected pyrolyzation section comprises transferring heat substantiallyby conduction.
 5096. The method of claim 5084, wherein producing themixture from the permeable formation further comprises producing mixturehaving an API gravity of at least about 25°.
 5097. The method of claim5084, wherein the produced mixture comprises condensable hydrocarbons,and wherein less than about 0.5% by weight, of the condensablehydrocarbons, when calculated on an atomic basis, is nitrogen.
 5098. Themethod of claim 5084, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 7% by weight, of thecondensable hydrocarbons, when calculated on an atomic basis, is oxygen.5099. The method of claim 5084, wherein the produced mixture comprisessulfur, and wherein less than about 5% by weight, of the condensablehydrocarbons, when calculated on an atomic basis, is sulfur.
 5100. Themethod of claim 5084, further comprising controlling a pressure withinat least a majority of the permeable formation, wherein the controlledpressure is at least about 2 bar absolute.
 5101. The method of claim5084, further comprising altering a pressure within the permeableformation to inhibit production of hydrocarbons from the permeableformation having carbon numbers greater than about
 25. 5102. The methodof claim 5084, further comprising: providing hydrogen (H₂) to the heatedsection to hydrogenate hydrocarbons within the section; and heating aportion of the section with heat from hydrogenation.
 5103. The method ofclaim 5084, wherein the produced mixture comprises condensablehydrocarbons and hydrogen, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 5104. The method of claim 5084, whereinproducing the mixture from the permeable formation further comprisesproducing the mixture in a production well, wherein the heating iscontrolled such that the mixture can be produced from the permeableformation, and wherein at least about 4 heat sources are disposed in thepermeable formation for each production well.
 5105. The method of claim5084, wherein producing the mixture from the permeable formation furthercomprises producing the mixture in a production well, wherein theheating is controlled such that the mixture can be produced from thepermeable formation, and wherein the production well is disposedsubstantially horizontally within the permeable formation.
 5106. Themethod of claim 5084, further comprising separating the mixture into agas stream and a liquid stream.
 5107. The method of claim 5084, furthercomprising separating the mixture into a gas stream and a liquid streamand separating the liquid stream into an aqueous stream and anon-aqueous stream.
 5108. The method of claim 5084, wherein the mixtureis produced from a production well, the method further comprisingheating a wellbore of the production well to inhibit condensation of themixture within the wellbore.
 5109. The method of claim 5084, wherein themixture is produced from a production well, wherein a wellbore of theproduction well comprises a heater element configured to heat thepermeable formation adjacent to the wellbore, and further comprisingheating the permeable formation with the heater element to produce themixture, wherein the mixture comprises non-condensable hydrocarbons andH₂.
 5110. The method of claim 5084, wherein a minimum mobilizationtemperature is about 75° C.
 5111. The method of claim 5084, wherein aminimum pyrolysis temperature is about 270° C.
 5112. The method of claim5084, further comprising maintaining the pressure within the permeableformation above about 2 bar absolute to inhibit production of fluidshaving carbon numbers above
 25. 5113. The method of claim 5084, furthercomprising controlling pressure within the permeable formation in arange from about atmospheric pressure to about 100 bar absolute, asmeasured at a wellhead of a production well, to control an amount ofcondensable fluids within the mixture, wherein the pressure is reducedto increase production of condensable fluids, and wherein the pressureis increased to increase production of non-condensable fluids.
 5114. Themethod of claim 5084, further comprising controlling pressure within thepermeable formation in a range from about atmospheric pressure to about100 bar absolute, as measured at a wellhead of a production well, tocontrol an API gravity of condensable fluids within the mixture whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 5115. The method ofclaim 5084, wherein mobilizing the hydrocarbons within the selectedmobilization section comprises reducing a viscosity of the hydrocarbons.5116. The method of claim 5084, further comprising providing a gas tothe permeable formation, wherein the gas is configured to increase aflow of the mobilized hydrocarbons from the selected mobilizationsection of the permeable formation to the selected pyrolyzation sectionof the permeable formation.
 5117. The method of claim 5084, furthercomprising providing a gas to the permeable formation, wherein the gasis configured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises carbon dioxide.
 5118. The method of claim 5084, furthercomprising providing a gas to the permeable formation, wherein the gasis configured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises nitrogen.
 5119. The method of claim 5084, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled.
 5120. The method of claim5084, further comprising providing a gas to the permeable formation,wherein the gas is configured to increase a flow of the mobilizedhydrocarbons from the selected mobilization section of the permeableformation to the selected pyrolyzation section of the permeableformation, the method further comprising controlling a pressure of theprovided gas such that the flow of the mobilized hydrocarbons iscontrolled, wherein the pressure of the provided gas is above about 2bar absolute.
 5121. The method of claim 5084, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled, wherein the pressure of theprovided gas is below about 70 bar absolute.
 5122. A method of treatinga hydrocarbon containing permeable formation in situ, comprising:providing heat from one or more heat sources to at least one portion ofthe permeable formation; allowing the heat to transfer from the one ormore heat sources to a selected mobilization section of the permeableformation such that the heat from the one or more heat sources canmobilize at least some of the hydrocarbons within the selectedmobilization section of the permeable formation; controlling the heatfrom the one or more heat sources such that an average temperaturewithin at least a majority of the selected mobilization section of thepermeable formation is less than about 150° C.; allowing the heat totransfer from the one or more heat sources to a selected pyrolyzationsection of the permeable formation such that the heat from the one ormore heat sources can pyrolyze at least some of the hydrocarbons withinthe selected pyrolyzation section of the permeable formation;controlling the heat from the one or more heat sources such that anaverage temperature within at least a majority of the selectedpyrolyzation section of the permeable formation is less than about 375°C.; allowing at least some of the mobilized hydrocarbons to flow fromthe selected mobilization section of the permeable formation to theselected pyrolyzation section of the permeable formation; and producinga mixture from the permeable formation.
 5123. The method of claim 5122,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from the one or more heat sources canmobilize at least some of the hydrocarbons within the selectedmobilization section of the permeable formation.
 5124. The method ofclaim 5122, wherein the one or more heat sources comprise at least twoheat sources, and wherein superposition of heat from the one or moreheat sources can pyrolyze at least some of the hydrocarbons within theselected pyrolyzation section of the permeable formation.
 5125. Themethod of claim 5122, wherein the one or more heat sources compriseelectrical heaters.
 5126. The method of claim 5122, wherein the one ormore heat sources comprise surface burners.
 5127. The method of claim5122, wherein the one or more heat sources comprise flamelessdistributed combustors.
 5128. The method of claim 5122, wherein the oneor more heat sources comprise natural distributed combustors.
 5129. Themethod of claim 5122, further comprising disposing the one or more heatsources horizontally within the permeable formation.
 5130. The method ofclaim 5122, further comprising controlling a pressure and a temperaturewithin at least a majority of the permeable formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 5131. The method of claim 5122,further comprising controlling the heat such that an average heatingrate of the selected pyrolyzation section is less than about 15° C./dayduring pyrolysis.
 5132. The method of claim 5122, wherein providing heatfrom the one or more heat sources to at least the portion of permeableformation comprises: heating a selected volume (V) of the hydrocarboncontaining permeable formation from the one or more heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.5133. The method of claim 5122 wherein allowing the heat to transferfrom the one or more heat sources to the selected mobilization sectionand/or the selected pyrolyzation section comprises transferring heatsubstantially by conduction.
 5134. The method of claim 5122, whereinproducing the mixture from the permeable formation further comprisesproducing a mixture having an API gravity of at least about 25°. 5135.The method of claim 5122, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 0.5% by weight, ofthe condensable hydrocarbons, when calculated on an atomic basis, isnitrogen.
 5136. The method of claim 5122 wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 7% byweight, of the condensable hydrocarbons, when calculated on an atomicbasis, is oxygen.
 5137. The method of claim 5122, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about5% by weight, of the condensable hydrocarbons, when calculated on anatomic basis, is sulfur.
 5138. The method of claim 5122, furthercomprising controlling a pressure within at least a majority of thepermeable formation, wherein the controlled pressure is at least about 2bar absolute.
 5139. The method of claim 5122, further comprisingaltering a pressure within the permeable formation to inhibit productionof hydrocarbons from the permeable formation having carbon numbersgreater than about
 25. 5140. The method of claim 5122, furthercomprising: providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 5141. The method of claim 5122, whereinthe produced mixture comprises condensable hydrocarbons and hydrogen,the method further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 5142. The method of claim 5122, wherein producing the mixturefrom the permeable formation further comprises producing mixture in aproduction well, wherein the heating is controlled such that the mixturecan be produced from the permeable formation, and wherein at least about4 heat sources are disposed in the permeable formation for eachproduction well.
 5143. The method of claim 5122, wherein producing themixture from the permeable formation further comprises producing mixturein a production well, wherein the heating is controlled such that themixture can be produced from the permeable formation, and wherein theproduction well is disposed substantially horizontally within thepermeable formation.
 5144. The method of claim 5122, further comprisingseparating the mixture into a gas stream and a liquid stream.
 5145. Themethod of claim 5122, further comprising separating the mixture into agas stream and a liquid stream and separating the liquid stream into anaqueous stream and a non-aqueous stream.
 5146. The method of claim 5122,wherein the mixture is produced from a production well, the methodfurther comprising heating a wellbore of the production well to inhibitcondensation of the mixture within the wellbore.
 5147. The method ofclaim 5122, wherein the mixture is produced from a production well,wherein a wellbore of the production well comprises a heater elementconfigured to heat the permeable formation adjacent to the wellbore, andfurther comprising heating the permeable formation with the heaterelement to produce the mixture, wherein the mixture comprisesnon-condensable hydrocarbons and H₂.
 5148. The method of claim 5122,wherein a minimum mobilization temperature is about 75° C.
 5149. Themethod of claim 5122, wherein a minimum pyrolysis temperature is about270° C.
 5150. The method of claim 5122, further comprising maintainingthe pressure within the permeable formation above about 2 bar absoluteto inhibit production of fluids having carbon numbers above
 25. 5151.The method of claim 5122, further comprising controlling pressure withinthe permeable formation in a range from about atmospheric pressure toabout 100 bar absolute, as measured at a wellhead of a production well,to control an amount of condensable fluids within the mixture, whereinthe pressure is reduced to increase production of condensable fluids,and wherein the pressure is increased to increase production ofnon-condensable fluids.
 5152. The method of claim 5122, furthercomprising controlling pressure within the permeable formation in arange from about atmospheric pressure to about 100 bar absolute, asmeasured at a wellhead of a production well, to control an API gravityof condensable fluids within the mixture, wherein the pressure isreduced to decrease the API gravity, and wherein the pressure isincreased to reduce the API gravity.
 5153. The method of claim 5122,wherein mobilizing the hydrocarbons within the selected mobilizationsection comprises reducing a viscosity of the hydrocarbons.
 5154. Themethod of claim 5122, further comprising providing a gas to thepermeable formation, wherein the gas is configured to increase a flow ofthe mobilized hydrocarbons from the selected mobilization section of thepermeable formation to the selected pyrolyzation section of thepermeable formation.
 5155. The method of claim 5122, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises carbon dioxide.
 5156. The method of claim 5122, furthercomprising providing a gas to the permeable formation, wherein the gasis configured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises nitrogen.
 5157. The method of claim 5122, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled.
 5158. The method of claim5122, further comprising providing a gas to the permeable formation,wherein the gas is configured to increase a flow of the mobilizedhydrocarbons from the selected mobilization section of the permeableformation to the selected pyrolyzation section of the permeableformation, the method further comprising controlling a pressure of theprovided gas such that the flow of the mobilized hydrocarbons iscontrolled, wherein the pressure of the provided gas is above about 2bar absolute.
 5159. The method of claim 5122, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled, wherein the pressure of theprovided gas is below about 100 bar absolute.
 5160. A method of treatinga hydrocarbon containing permeable formation in situ, comprising:providing heat from one or more heat sources to at least one portion ofthe permeable formation; allowing the heat to transfer from the one ormore heat sources to a selected mobilization section of the permeableformation such that the heat from the one or more heat sources canmobilize at least some of the hydrocarbons within the selectedmobilization section of the permeable formation; controlling the heatfrom the one or more heat sources such that an average temperaturewithin at least a majority of the selected mobilization section of thepermeable formation is less than about 150° C.; allowing the heat totransfer from the one or more heat sources to a selected pyrolyzationsection of the permeable formation such that the heat from the one ormore heat sources can pyrolyze at least some of the hydrocarbons withinthe selected pyrolyzation section of the permeable formation;controlling the heat from the one or more heat sources such that anaverage temperature within at least a majority of the selectedpyrolyzation section of the permeable formation is less than about 375°C.; allowing at least some of the mobilized hydrocarbons to flow fromthe selected mobilization section of the permeable formation to theselected pyrolyzation section of the permeable formation; providing agas to the permeable formation, wherein the gas is configured toincrease a flow of the mobilized hydrocarbons from the selectedmobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation; and producing a mixturefrom the permeable formation.
 5161. The method of claim 5160, whereinthe one or more heat sources comprise at least two heat sources, andwherein the heat from the one or more heat sources can mobilize at leastsome of the hydrocarbons within the selected mobilization section of thepermeable formation.
 5162. The method of claim 5160, wherein the one ormore heat sources comprise at least two heat sources, and wherein theheat from the one or more heat sources can pyrolyze at least some of thehydrocarbons within the selected pyrolyzation section of the permeableformation.
 5163. The method of claim 5160, wherein the one or more heatsources comprise electrical heaters.
 5164. The method of claim 5160,wherein the one or more heat sources comprise surface burners.
 5165. Themethod of claim 5160, wherein the one or more heat sources compriseflameless distributed combustors.
 5166. The method of claim 5160,wherein the one or more heat sources comprise natural distributedcombustors.
 5167. The method of claim 5160, further comprising disposingthe one or more heat sources horizontally within the permeableformation.
 5168. The method of claim 5160, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe permeable formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 5169. The method of claim 5160, further comprisingcontrolling the heat such that an average heating rate of the selectedpyrolyzation section is less than about 15° C./day during pyrolysis.5170. The method of claim 5160, wherein providing heat from the one ormore heat sources to at least the portion of permeable formationcomprises: heating a selected volume (V) of the hydrocarbon containingpermeable formation from the one or more heat sources, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 5171. Themethod of claim 5160, wherein allowing the heat to transfer from the oneor more heat sources to the selected mobilization section and/or theselected pyrolyzation section comprises transferring heat substantiallyby conduction.
 5172. The method of claim 5160, wherein producing mixturefrom the permeable formation further comprises producing mixture havingan API gravity of at least about 25°.
 5173. The method of claim 5160,wherein the produced mixture comprises condensable hydrocarbons, andwherein less than about 0.5% by weight, of the condensable hydrocarbons,when calculated on an atomic basis, is nitrogen.
 5174. The method ofclaim 5160, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 7% by weight, of thecondensable hydrocarbons, when calculated on an atomic basis, is oxygen.5175. The method of claim 5160, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 5% by weight, ofthe condensable hydrocarbons, when calculated on an atomic basis, issulfur.
 5176. The method of claim 5160, further comprising controlling apressure within at least a majority of the permeable formation, whereinthe controlled pressure is at least about 2 bar absolute.
 5177. Themethod of claim 5160, further comprising altering a pressure within thepermeable formation to inhibit production of hydrocarbons from thepermeable formation having carbon numbers greater than about
 25. 5178.The method of claim 5160, further comprising: providing hydrogen (H₂) tothe heated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 5179. Themethod of claim 5160, wherein the produced mixture comprises condensablehydrocarbons and hydrogen, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 5180. The method of claim 5160, whereinproducing the mixture from the permeable formation further comprisesproducing the mixture in a production well, wherein the heating iscontrolled such that the mixture can be produced from the permeableformation, and wherein at least about 4 heat sources are disposed in thepermeable formation for each production well.
 5181. The method of claim5160, wherein producing the mixture from the permeable formation furthercomprises producing the mixture in a production well, wherein theheating is controlled such that the mixture can be produced from thepermeable formation, and wherein the production well is disposedsubstantially horizontally within the permeable formation.
 5182. Themethod of claim 5160, further comprising separating the mixture into agas stream and a liquid stream.
 5183. The method of claim 5160, furthercomprising separating the mixture into a gas stream and a liquid streamand separating the liquid stream into an aqueous stream and anon-aqueous stream.
 5184. The method of claim 5160, wherein the mixtureis produced from a production well, the method further comprisingheating a wellbore of the production well to inhibit condensation of themixture within the wellbore.
 5185. The method of claim 5160, wherein themixture is produced from a production well, where in a wellbore of theproduction well comprises a heater element configured to heat thepermeable formation adjacent to the wellbore, and further comprisingheating the permeable formation with the heater element to produce themixture, wherein the mixture comprise non-condensable hydrocarbons andH₂.
 5186. The method of claim 5160, wherein a minimum mobilizationtemperature is about 75° C.
 5187. The method of claim 5160, wherein aminimum pyrolysis temperature is about 270” C.
 5188. The method of claim5160, further comprising maintaining the pressure within the permeableformation above about 2 bar absolute to inhibit production of fluidshaving carbon numbers above
 25. 5189. The method of claim 5160, furthercomprising controlling pressure within the permeable formation in arange from about atmospheric pressure to about 100 bar absolute, asmeasured at a wellhead of a production well, to control an amount ofcondensable fluids within the mixture, wherein the pressure is reducedto increase production of condensable fluids, and wherein the pressureis increased to increase production of non-condensable fluids.
 5190. Themethod of claim 5160, further comprising controlling pressure within thepermeable formation in a range from about atmospheric pressure to about100 bar absolute, as measured at a wellhead of a production well, tocontrol an API gravity of condensable fluids within the mixture, whereinthe pressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 5191. The method ofclaim 5160, wherein mobilizing the hydrocarbons within the selectedmobilization section comprises reducing a viscosity of the hydrocarbons.5192. The method of claim 5160, wherein the provided gas comprisescarbon dioxide.
 5193. The method of claim 5160, wherein the provided gascomprises nitrogen.
 5194. The method of claim 5160, further comprisingcontrolling a pressure of the provided gas such that the flow of themobilized hydrocarbons is controlled.
 5195. The method of claim 5160,further comprising controlling a pressure of the provided gas such thatthe flow of the mobilized hydrocarbons is controlled, wherein thepressure of the provided gas is above about 2 bar absolute.
 5196. Themethod of claim 5160, further comprising controlling a pressure of theprovided gas such that the flow of the mobilized hydrocarbons iscontrolled, wherein the pressure of the provided gas is below about 100bar absolute.
 5197. A method of treating a hydrocarbon containingpermeable formation in situ, comprising: providing heat from one or moreheat sources to at least one portion of the permeable formation;allowing the heat to transfer from the one or more heat sources to aselected mobilization section of the permeable formation such that theheat from the one or more heat sources can mobilize at least some of thehydrocarbons within the selected mobilization section of the permeableformation; controlling the heat from the one or more heat sources suchthat an average temperature within at least a majority of the selectedmobilization section of the permeable formation is less than about 150°C.; allowing the heat to transfer from the one or more heat sources to aselected pyrolyzation section of the permeable formation such that theheat from the one or more heat sources can pyrolyze at least some of thehydrocarbons within the selected pyrolyzation section of the permeableformation; controlling the heat from the one or more heat sources suchthat an average temperature within at least a majority of the selectedpyrolyzation section of the permeable formation is less than about 375°C.; allowing at least some of the mobilized hydrocarbons to flow fromthe selected mobilization section of the permeable formation to theselected pyrolyzation section of the permeable formation; providing agas to the permeable formation, wherein the gas is configured toincrease a flow of the mobilized hydrocarbons from the selectedmobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation; controlling a pressureof the provided gas such that the flow of the mobilized hydrocarbons iscontrolled; and producing a mixture from the permeable formation. 5198.The method of claim 5197, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from theone or more heat sources can mobilize at least some of the hydrocarbonswithin the selected mobilization section of the permeable formation.5199. The method of claim 5197, wherein the one or more heat sourcescomprise at least two heat sources, and wherein superposition of heatfrom the one or more heat sources can pyrolyze at least some of thehydrocarbons within the selected pyrolyzation section of the permeableformation.
 5200. The method of claim 5197, wherein the one or more heatsources comprise electrical heaters.
 5201. The method of claim 5197,wherein the one or more heat sources comprise surface burners.
 5202. Themethod of claim 5197, wherein the one or more heat sources compriseflameless distributed combustors.
 5203. The method of claim 5197,wherein the one or more heat sources comprise natural distributedcombustors.
 5204. The method of claim 5197, further comprising disposingthe one or more heat sources horizontally within the permeableformation.
 5205. The method of claim 5197, further comprisingcontrolling a pressure and a temperature within at least a majority ofthe permeable formation, wherein the pressure is controlled as afunction of temperature, or the temperature is controlled as a functionof pressure.
 5206. The method of claim 5197, further comprisingcontrolling the heat such that an average heating rate of the selectedpyrolyzation section is less than about 15° C./day during pyrolysis.5207. The method of claim 5197, wherein providing heat from the one ormore heat sources to at least the portion of permeable formationcomprises: heating a selected volume (V) of the hydrocarbon containingpermeable formation from the one or more heat sources, wherein theformation has an average heat capacity (C_(v)), and wherein the heatingpyrolyzes at least some hydrocarbons within the selected volume of theformation; and wherein heating energy/day provided to the volume isequal to or less than Pwr, wherein Pwr is calculated by the equation:Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, h is anaverage heating rate of the formation, ρ_(B) is formation bulk density,and wherein the heating rate is less than about 10° C./day.
 5208. Themethod of claim 5197, wherein allowing the heat to transfer from the oneor more heat sources to the selected mobilization section and/or theselected pyrolyzation section comprises transferring heat substantiallyby conduction.
 5209. The method of claim 5197, wherein producing themixture from the permeable formation further comprises producing mixturehaving an API gravity of at least about 25°.
 5210. The method of claim5197, wherein the produced mixture comprises condensable hydrocarbons,and wherein less than about 0.5% by weight, of the condensablehydrocarbons, when calculated on an atomic basis, is nitrogen.
 5211. Themethod of claim 5197, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 7% by weight, of thecondensable hydrocarbons, when calculated on an atomic basis, is oxygen.5212. The method of claim 5197, wherein the produced mixture comprisescondensable hydrocarbons, and wherein less than about 5% by weight, ofthe condensable hydrocarbons, when calculated on an atomic basis, issulfur.
 5213. The method of claim 5197, further comprising controlling apressure within at least a majority of the permeable formation, whereinthe controlled pressure is at least about 2 bar absolute.
 5214. Themethod of claim 5197, further comprising altering a pressure within thepermeable formation to inhibit production of hydrocarbons from thepermeable formation having carbon numbers greater than about
 25. 5215.The method of claim 5197, further comprising: providing hydrogen (H₂) tothe heated section to hydrogenate hydrocarbons within the section; andheating a portion of the section with heat from hydrogenation.
 5216. Themethod of claim 5197, wherein the produced mixture comprises condensablehydrocarbons and hydrogen, the method further comprising hydrogenating aportion of the produced condensable hydrocarbons with at least a portionof the produced hydrogen.
 5217. The method of claim 5197, whereinproducing the mixture from the permeable formation further comprisesproducing the mixture in a production well, wherein the heating iscontrolled such that the mixture can be produced from the permeableformation, and wherein at least about 4 heat sources are disposed in thepermeable formation for each production well.
 5218. The method of claim5197, wherein producing the mixture from the permeable formation furthercomprises producing the mixture in a production well, wherein theheating is controlled such that the mixture can be produced from thepermeable formation, and wherein the production well is disposedsubstantially horizontally within the permeable formation.
 5219. Themethod of claim 5197, further comprising separating the mixture into agas stream and a liquid stream.
 5220. The method of claim 5197, furthercomprising separating the mixture into a gas stream and a liquid streamand separating the liquid stream into an aqueous stream and anon-aqueous stream.
 5221. The method of claim 5197, wherein the mixtureis produced from a production well the method further comprising heatinga wellbore of the production well to inhibit condensation of the mixturewithin the wellbore.
 5222. The method of claim 5197, wherein the mixtureis produced from a production well, wherein a wellbore of the productionwell comprises a heater element configured to heat the permeableformation adjacent to the wellbore, and further comprising heating thepermeable formation with the heater element to produce the mixture,wherein the mixture comprises non-condensable hydrocarbons and H₂. 5223.The method of claim 5197, wherein a minimum mobilization temperature isabout 75° C.
 5224. The method of claim 5197, wherein a minimum pyrolysistemperature is about 270° C.
 5225. The method of claim 5197 furthercomprising maintaining the pressure within the permeable formation aboveabout 2 bar absolute to inhibit production of fluids having carbonnumbers above
 25. 5226. The method of claim 5197, further comprisingcontrolling pressure within the permeable formation in a range fromabout atmospheric pressure to about 100 bar absolute, as measured at awellhead of a production well, to control an amount of condensablefluids within the mixture, wherein the pressure is reduced to increaseproduction of condensable fluids, and wherein the pressure is increasedto increase production of non-condensable fluids.
 5227. The method ofclaim 5197, further comprising controlling pressure within the permeableformation in a range from about atmospheric pressure to about 100 barabsolute, as measured at a wellhead of a production well, to control anAPI gravity of condensable fluids within the mixture, wherein thepressure is reduced to decrease the API gravity, and wherein thepressure is increased to reduce the API gravity.
 5228. The method ofclaim 5197, wherein mobilizing the hydrocarbons within the selectedmobilization section comprises reducing a viscosity of the hydrocarbons.5229. The method of claim 5197, wherein the provided gas comprisescarbon dioxide.
 5230. The method of claim 5197, wherein the provided gascomprises nitrogen.
 5231. The method of claim 5197, wherein the pressureof the provided gas is above about 2 bar absolute.
 5232. The method ofclaim 5197, wherein the pressure of the provided gas is below about 70bar absolute.
 5233. A method of treating a hydrocarbon containingpermeable formation in situ, comprising: providing heat from one or moreheat sources to at least one portion of the permeable formation:allowing the heat to transfer from the one or more heat sources to aselected mobilization section of the permeable formation such that theheat from the one or more heat sources can mobilize at least some of thehydrocarbons within the selected mobilization section of the permeableformation: controlling the heat from the one or more heat sources suchthat an average temperature within at least a majority of the selectedmobilization section of the permeable formation is less than about 150°C.; allowing the heat to transfer from the one or more heat sources to aselected pyrolyzation section of the permeable formation such that theheat from the one or more heat sources can pyrolyze at least some of thehydrocarbons within the selected pyrolyzation section of the permeableformation; controlling the heat from the one or more heat sources suchthat an average temperature within at least a majority of the selectedpyrolyzation section of the permeable formation is less than about 375°C.; and producing a mixture from the permeable formation in a productionwell, wherein the production well is disposed substantially horizontallywithin the permeable formation.
 5234. The method of claim 5233, whereinthe one or more heat sources comprise at least two heat sources, andwherein superposition of heat from the one or more heat sources canmobilize at least some of the hydrocarbons within the selectedmobilization section of the permeable formation.
 5235. The method ofclaim 5233, wherein the one or more heat sources comprise at least twoheat sources, and wherein superposition of heat from the one or moreheat sources can pyrolyze at least some of the hydrocarbons within theselected pyrolyzation section of the permeable formation.
 5236. Themethod of claim 5233, wherein the one or more heat sources compriseelectrical heaters.
 5237. The method of claim 5233, wherein the one ormore heat sources comprise surface burners.
 5238. The method of claim5233, wherein the one or more heat sources comprise flamelessdistributed combustors.
 5239. The method of claim 5233, wherein the oneor more heat sources comprise natural distributed combustors.
 5240. Themethod of claim 5233, further comprising disposing the one or more heatsources horizontally within the permeable formation.
 5241. The method ofclaim 5233, further comprising controlling a pressure and a temperaturewithin at least a majority of the permeable formation, wherein thepressure is controlled as a function of temperature, or the temperatureis controlled as a function of pressure.
 5242. The method of claim 5233,further comprising controlling the heat such that an average heatingrate of the selected pyrolyzation section is less than about 15° C./dayduring pyrolysis.
 5243. The method of claim 5233, wherein providing heatfrom the one or more heat sources to at least the portion of permeableformation comprises: heating a selected volume (V) of the hydrocarboncontaining permeable formation from the one or more heat sources,wherein the formation has an average heat capacity (C_(v)), and whereinthe heating pyrolyzes at least some hydrocarbons within the selectedvolume of the formation; and wherein heating energy/day provided to thevolume is equal to or less than Pwr, wherein Pwr is calculated by theequation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr is the heating energy/day, his an average heating rate of the formation, ρ_(B) is formation bulkdensity, and wherein the heating rate is less than about 10° C./day.5244. The method of claim 5233, wherein allowing the heat to transferfrom the one or more heat sources to the selected mobilization sectionand/or the selected pyrolyzation section comprises transferring heatsubstantially by conduction.
 5245. The method of claim 5233, whereinproducing mixture from the permeable formation further comprisesproducing mixture having an API gravity of at least about 25°.
 5246. Themethod of claim 5233, wherein the produced mixture comprises condensablehydrocarbons, and wherein less than about 0.5% by weight, of thecondensable hydrocarbons, when calculated on an atomic basis, isnitrogen.
 5247. The method of claim 5233, wherein the produced mixturecomprises condensable hydrocarbons, and wherein less than about 7% byweight, of the condensable hydrocarbons, when calculated on an atomicbasis, is oxygen.
 5248. The method of claim 5233, wherein the producedmixture comprises condensable hydrocarbons, and wherein less than about5% by weight, of the condensable hydrocarbons, when calculated on anatomic basis, is sulfur.
 5249. The method of claim 5233, furthercomprising controlling a pressure within at least a majority of thepermeable formation, wherein the controlled pressure is at least about 2bar absolute.
 5250. The method of claim 5233 further comprising alteringa pressure within the permeable formation to inhibit production ofhydrocarbons from the permeable formation having carbon numbers greaterthan about
 25. 5251. The method of claim 5233, further comprising:providing hydrogen (H₂) to the heated section to hydrogenatehydrocarbons within the section; and heating a portion of the sectionwith heat from hydrogenation.
 5252. The method of claim 5233, whereinthe produced mixture comprises condensable hydrocarbons and hydrogen,the method further comprising hydrogenating a portion of the producedcondensable hydrocarbons with at least a portion of the producedhydrogen.
 5253. The method of claim 5233, wherein producing the mixturefrom the permeable formation further comprises producing the mixture ina production well, wherein the heating is controlled such that themixture can be produced from the permeable formation, and wherein atleast about 4 heat sources are disposed in the permeable formation foreach production well.
 5254. The method of claim 5233, further comprisingseparating the mixture into a gas stream and a liquid stream.
 5255. Themethod of claim 5233, further comprising separating the mixture into agas stream and a liquid stream and separating the liquid stream into anaqueous stream and a non-aqueous stream.
 5256. The method of claim 5233,wherein the mixture is produced from a production well, the methodfurther comprising heating a wellbore of the production well to inhibitcondensation of the mixture within the wellbore.
 5257. The method ofclaim 5233, wherein the mixture is produced from a production well,wherein a wellbore of the production well comprises a heater elementconfigured to heat the permeable formation adjacent to the wellbore, andfurther comprising heating the permeable formation with the heaterelement to produce the mixture, wherein the mixture comprisesnon-condensable hydrocarbons and H₂.
 5258. The method of claim 5233,wherein a minimum mobilization temperature is about 75° C.
 5259. Themethod of claim 5233, wherein a minimum pyrolysis temperature is about270° C.
 5260. The method of claim 5233, further comprising maintainingthe pressure within the permeable formation above about 2 bar absoluteto inhibit production of fluids having carbon numbers above
 25. 5261.The method of claim 5233, further comprising controlling pressure withinthe permeable formation in a range from about atmospheric pressure toabout 100 bar absolute, as measured at a wellhead of a production well,to control an amount of condensable fluids within the mixture, whereinthe pressure is reduced to increase production of condensable fluids,and wherein the pressure is increased to increase production ofnon-condensable fluids.
 5262. The method of claim 5233, furthercomprising controlling pressure within the permeable formation in arange from about atmospheric pressure to about 100 bar absolute, asmeasured at a wellhead of a production well, to control an API gravityof condensable fluids within the mixture, wherein the pressure isreduced to decrease the API gravity, and wherein the pressure isincreased to reduce the API gravity.
 5263. The method of claim 5233,wherein mobilizing the hydrocarbons within the selected mobilizationsection comprises reducing a viscosity of the hydrocarbons.
 5264. Themethod of claim 5233, further comprising providing a gas to thepermeable formation, wherein the gas is configured to increase a flow ofthe mobilized hydrocarbons from the selected mobilization section of thepermeable formation to the selected pyrolyzation section of thepermeable formation.
 5265. The method of claim 5233, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises carbon dioxide.
 5266. The method of claim 5233, furthercomprising providing a gas to the permeable formation, wherein the gasis configured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, and wherein the gascomprises nitrogen.
 5267. The method of claim 5233, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled.
 5268. The method of claim5233, further comprising providing a gas to the permeable formation,wherein the gas is configured to increase a flow of the mobilizedhydrocarbons from the selected mobilization section of the permeableformation to the selected pyrolyzation section of the permeableformation, the method further comprising controlling a pressure of theprovided gas such that the flow of the mobilized hydrocarbons iscontrolled, wherein the pressure of the provided gas is above about 2bar absolute.
 5269. The method of claim 5233, further comprisingproviding a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons from theselected mobilization section of the permeable formation to the selectedpyrolyzation section of the permeable formation, the method furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled, wherein the pressure of theprovided gas is below about 70 bar absolute.
 5270. A method of treatinga hydrocarbon containing permeable formation in situ, comprising:providing heat from one or more heat sources to at least one portion ofthe permeable formation: allowing the heat to transfer from the one ormore heat sources to a selected mobilization section of the permeableformation such that the heat from the one or more heat sources canmobilize at least some of the hydrocarbons within the selectedmobilization section of the permeable formation; controlling the heatfrom the one or more heat sources such that an average temperaturewithin at least a majority of the selected mobilization section of thepermeable formation is less than about 150° C.; providing a gas to thepermeable formation, wherein the gas is configured to increase a flow ofthe mobilized hydrocarbons within the permeable formation; and producinga mixture from the permeable formation.
 5271. The method of claim 5270,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from the one or more heat sources canmobilize at least some of the hydrocarbons within the selectedmobilization section of the permeable formation.
 5272. The method ofclaim 5270, wherein the one or more heat sources comprise electricalheaters.
 5273. The method of claim 5270, wherein the one or more heatsources comprise surface burners.
 5274. The method of claim 5270,wherein the one or more heat sources comprise flameless distributedcombustors.
 5275. The method of claim 5270, wherein the one or more heatsources comprise natural distributed combustors.
 5276. The method ofclaim 5270, further comprising disposing the one or more heat sourceshorizontally within the permeable formation.
 5277. The method of claim5270, further comprising controlling a pressure and a temperature withinat least a majority of the permeable formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 5278. The method of claim 5270,wherein providing heat from the one or more heat sources to at least theportion of permeable formation comprises: heating a selected volume (V)of the hydrocarbon containing permeable formation from the one or moreheat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 5279. The method of claim 5270, wherein allowingthe heat to transfer from the one or more heat sources to the selectedmobilization section comprises transferring heat substantially byconduction.
 5280. The method of claim 5270, further comprisingcontrolling a pressure within at least a majority of the permeableformation, wherein the controlled pressure is at least about 2 barabsolute.
 5281. The method of claim 5270, wherein producing the mixturefrom the permeable formation further comprises producing the mixture ina production well, wherein the heating is controlled such that themixture can be produced from the permeable formation, and wherein atleast about 4 heat sources are disposed in the permeable formation foreach production well.
 5282. The method of claim 5270, wherein producingthe mixture from the permeable formation further comprises producing themixture in a production well, wherein the heating is controlled suchthat the mixture can be produced from the permeable formation andwherein the production well is disposed substantially horizontallywithin the permeable formation.
 5283. The method of claim 5270, farthercomprising separating the mixture into a gas stream and a liquid stream.5284. The method of claim 5270, further comprising separating themixture into a gas stream and a liquid stream and separating the liquidstream into an aqueous stream and a non-aqueous stream.
 5285. The methodof claim 5270, wherein the mixture is produced from a production well,the method further comprising heating a wellbore of the production wellto inhibit condensation of the mixture within the wellbore.
 5286. Themethod of claim 5270, wherein the mixture is produced from a productionwell, wherein a wellbore of the production well comprises a heaterelement configured to heat the permeable formation adjacent to thewellbore, and further comprising heating the permeable formation withthe heater element to produce the mixture, wherein the mixture comprisenon-condensable hydrocarbons and H₂.
 5287. The method of claim 5270,wherein a minimum mobilization temperature is about 75° C.
 5288. Themethod of claim 5270, wherein mobilizing the hydrocarbons within theselected mobilization section comprises reducing a viscosity of thehydrocarbons.
 5289. The method of claim 5270, wherein the provided gascomprises carbon dioxide.
 5290. The method of claim 5270, wherein theprovided gas comprises nitrogen.
 5291. The method of claim 5270, furthercomprising controlling a pressure of the provided gas such that the flowof the mobilized hydrocarbons is controlled.
 5292. The method of claim5270, further comprising controlling a pressure of the provided gas suchthat the flow of the mobilized hydrocarbons is controlled, wherein thepressure of the provided gas is above about 2 bar absolute.
 5293. Themethod of claim 5270, further comprising controlling a pressure of theprovided gas such that the flow of the mobilized hydrocarbons iscontrolled, wherein the pressure of the provided gas is below about 70bar absolute.
 5294. A method of treating a hydrocarbon containingpermeable formation in situ, comprising: providing heat from one or moreheat sources to at least one portion of the permeable formation;allowing the heat to transfer from the one or more heat sources to aselected mobilization section of the permeable formation such that theheat from the one or more heat sources can mobilize at least some of thehydrocarbons within the selected mobilization section of the permeableformation; controlling the heat from the one or more heat sources suchthat an average temperature within at least a majority of the selectedmobilization section of the permeable formation is less than about 150°C.; providing a gas to the permeable formation, wherein the gas isconfigured to increase a flow of the mobilized hydrocarbons within thepermeable formation; controlling a pressure of the provided gas suchthat the flow of the mobilized hydrocarbons is controlled; and producinga mixture from the permeable formation.
 5295. The method of claim 5294,wherein the one or more heat sources comprise at least two heat sources,and wherein superposition of heat from the one or more heat sources canmobilize at least some of the hydrocarbons within the selectedmobilization section of the permeable formation.
 5296. The method ofclaim 5294, wherein the one or more heat sources comprise electricalheaters.
 5297. The method of claim 5294, wherein the one or more heatsources comprise surface burners.
 5298. The method of claim 5294,wherein the one or more heat sources comprise flameless distributedcombustors.
 5299. The method of claim 5294, wherein the one or more heatsources comprise natural distributed combustors.
 5300. The method ofclaim 5294, further comprising disposing the one or more heat sourceshorizontally within the permeable formation.
 5301. The method of claim5294, further comprising controlling a pressure and a temperature withinat least a majority of the permeable formation, wherein the pressure iscontrolled as a function of temperature, or the temperature iscontrolled as a function of pressure.
 5302. The method of claim 5294,wherein providing heat from the one or more heat sources to at least theportion of permeable formation comprises: heating a selected volume (V)of the hydrocarbon containing permeable formation from the one or moreheat sources, wherein the formation has an average heat capacity(C_(v)), and wherein the heating pyrolyzes at least some hydrocarbonswithin the selected volume of the formation; and wherein heatingenergy/day provided to the volume is equal to or less than Pwr, whereinPwr is calculated by the equation: Pwr=h*V*C _(v)*ρ_(B) wherein Pwr isthe heating energy/day, h is an average heating rate of the formation,ρ_(B) is formation bulk density, and wherein the heating rate is lessthan about 10° C./day.
 5303. The method of claim 5294, wherein allowingthe heat to transfer from the one or more heat sources to the selectedmobilization section comprises transferring heat substantially byconduction.
 5304. The method of claim 5294, further comprisingcontrolling a pressure within at least a majority of the permeableformation, wherein the controlled pressure is at least about 2 barabsolute.
 5305. The method of claim 5294, wherein producing the mixturefrom the permeable formation further comprises producing the mixture ina production well, wherein the heating is controlled such that themixture can be produced from the permeable formation, and wherein atleast about 4 heat sources are disposed in the permeable formation foreach production well.
 5306. The method of claim 5294, wherein producingthe mixture from the permeable formation further comprises producing themixture in a production well, wherein the heating is controlled suchthat the mixture can be produced from the permeable formation, andwherein the production well is disposed substantially horizontallywithin the permeable formation.
 5307. The method of claim 5294, furthercomprising separating the mixture into a gas stream and a liquid stream.5308. The method of claim 5294, further comprising separating themixture into a gas stream and a liquid stream and separating the liquidstream into an aqueous stream and a non-aqueous stream.
 5309. The methodof claim 5294, wherein the mixture is produced from a production well,the method further comprising heating a wellbore of the production wellto inhibit condensation of the mixture within the wellbore.
 5310. Themethod of claim 5294, wherein the mixture is produced from a productionwell, wherein a wellbore of the production well comprises a heaterelement configured to heat the permeable formation adjacent to thewellbore, and further comprising heating the permeable formation withthe heater element to produce the mixture, wherein the mixture comprisenon-condensable hydrocarbons and H₂.
 5311. The method of claim 5294,wherein a minimum mobilization temperature is about 75° C.
 5312. Themethod of claim 5294, wherein mobilizing the hydrocarbons within theselected mobilization section comprises reducing a viscosity of thehydrocarbons.
 5313. The method of claim 5294, wherein the provided gascomprises carbon dioxide.
 5314. The method of claim 5294, wherein theprovided gas comprises nitrogen.
 5315. The method of claim 5294, whereinthe pressure of the provided gas is above about 2 bar absolute. 5316.The method of claim 5294, wherein the pressure of the provided gas isbelow about 70 bar absolute.
 5317. A method for treating hydrocarbons inat least a portion of a hydrocarbon containing formation, wherein theportion has an average permeability of less than about 10 millidarcy,comprising: providing heat from one or more heat sources to theformation; allowing the heat to transfer from one or more of the heatsources to a selected section of the formation such that heat from theheat sources pyrolyzes at least some hydrocarbons within the selectedsection, and wherein heat from the heat sources increases thepermeability of at least a portion of the selected section; andproducing a mixture comprising hydrocarbons from the formation. 5318.The method of claim 5317, wherein the one or more heat sources compriseat least two heat sources, and wherein superposition of heat from atleast the two heat sources pyrolyzes at least some hydrocarbons withinthe selected section of the formation, and wherein superposition of heatfrom at least the two heat sources increases the permeability of atleast the portion of the selected section.
 5319. The method of claim5317, further comprising allowing heat to transfer from at least one ofthe heat sources to the selected section to create thermal fractures inthe formation wherein the thermal fractures substantially increase thepermeability of the selected section.
 5320. The method of claim 5317,wherein the heat is provided such that an average temperature in theselected section ranges from approximately about 270° C. to about 375°C.
 5321. The method of claim 5317, wherein at least one of the heatsources comprises an electrical heater located in the formation. 5322.The method of claim 5317, wherein at least one of the heat sources islocated in a heater well, and wherein at least one of the heater wellscomprises a conduit located in the formation, and further comprisingheating the conduit by flowing a hot fluid through the conduit. 5323.The method of claim 5317, wherein at least some of the heat sources arearranged in a triangular pattern.
 5324. The method of claim 5317,further comprising: monitoring a composition of the produced mixture;and controlling a pressure in at least a portion of the formation tocontrol the composition of the produced mixture.
 5325. The method ofclaim 5324, wherein the pressure is controlled by a valve proximate to alocation where the mixture is produced.
 5326. The method of claim 5324,wherein the pressure is controlled such that pressure proximate to oneor more of the heat sources is greater than a pressure proximate to alocation where the fluid is produced.
 5327. The method of claim 5317,wherein an average distance between heat sources is between about 2 m toabout 8 m.
 5328. A method for treating hydrocarbons in at least aportion of a hydrocarbon containing formation, wherein the portion hasan average permeability of less than about 10 millidarcy, comprising:providing heat from one or more heat sources to the formation; allowingthe heat to transfer from one or more of the heat sources to a selectedsection of the formation such that heat from the heat sources pyrolyzesat least some hydrocarbons within the selected section, and wherein heatfrom the heat sources vaporizes at least a portion of the hydrocarbonsin the selected section; and producing a mixture comprising hydrocarbonsfrom the formation.
 5329. The method of claim 5328, wherein the one ormore heat sources comprise at least two heat sources, and whereinsuperposition of heat from at least the two heat sources pyrolyzes atleast some hydrocarbons within the selected section of the formation,and wherein superposition of heat from at least the two heat sourcesvaporizes at least the portion of the hydrocarbons in the selectedsection.
 5330. The method of claim 5328, further comprising allowingheat to transfer from at least one of the heat sources to the selectedsection to create thermal fractures in the formation, wherein thethermal fractures substantially increase the permeability of theselected section.
 5331. The method of claim 5328, wherein the heat isprovided such that an average temperature in the selected section rangesfrom approximately about 270° C. to about 375° C.
 5332. The method ofclaim 5328, wherein at least one of the heat sources comprises anelectrical heater located in the formation.
 5333. The method of claim5328, wherein at least one of the heat sources is located in a heaterwell, and wherein at least one of the heater wells comprises a conduitlocated in the formation, and further comprising heating the conduit byflowing a hot fluid through the conduit.
 5334. The method of claim 5328,wherein at least some of the heat sources are arranged in a triangularpattern.
 5335. The method of claim 5328, further comprising: monitoringa composition of the produced mixture; and controlling a pressure in atleast a portion of the formation to control the composition of theproduced mixture.
 5336. The method of claim 5335, wherein the pressureis controlled by a valve proximate to a location where the mixture isproduced.
 5337. The method of claim 5335, wherein the pressure iscontrolled such that pressure proximate to one or more of the heatsources is greater than a pressure proximate to a location where themixture is produced.
 5338. The method of claim 5328, wherein an averagedistance between heat sources is between about 2 m to about 8 m.
 5339. Amethod for treating hydrocarbons in at least a portion of a hydrocarboncontaining formation, wherein the portion has an average permeability ofless than about 10 millidarcy, comprising: providing heat from one ormore heat sources to the formation, wherein at least one of the heatsources is located in a heater well; allowing the heat to transfer fromone or more of the heat sources to a selected section of the formationsuch that heat from the heat sources pyrolyzes at least somehydrocarbons within the selected section, and wherein heat from the heatsources pressurizes at least a portion of the selected section; andproducing a mixture comprising hydrocarbons from the formation, whereinthe mixture is produced from one or more heater wells.
 5340. The methodof claim 5339, wherein the one or more heat sources comprise at leasttwo heat sources, and wherein superposition of heat from at least thetwo heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 5341. The method of claim 5339,further comprising producing fluid from at least one heater well inwhich is positioned the heat source of the one or more heat sources.5342. The method of claim 5339, further comprising allowing heat totransfer from at least one of the heat sources to the selected sectionto create thermal fractures in the formation, wherein the thermalfractures substantially increase the permeability of the selectedsection.
 5343. The method of claim 5339, wherein the heat is providedsuch that an average temperature in the selected section ranges fromapproximately about 270° C. to about 375° C.
 5344. The method of claim5339, wherein at least one of the heat sources comprises an electricalheater located in the formation.
 5345. The method of claim 5339, whereinat least one of the heat sources is located in a heater well, andwherein at least one of the heater wells comprises a conduit located inthe formation, and further comprising heating the conduit by flowing ahot fluid through the conduit.
 5346. The method of claim 5339, whereinat least some of the heat sources are arranged in a triangular pattern.5347. The method of claim 5339, further comprising: monitoring acomposition of the produced mixture; and controlling a pressure in atleast a portion of the formation to control the composition of theproduced mixture.
 5348. The method of claim 5347, wherein the pressureis controlled by a valve proximate to a location where the mixture isproduced.
 5349. The method of claim 5347, wherein the pressure iscontrolled such that pressure proximate to one or more of the heatsources is greater than a pressure proximate to a location where themixture is produced.
 5350. The method of claim 5339 wherein an averagedistance between heat sources is between about 2 m to about 8 m.
 5351. Amethod for treating hydrocarbons in at least a portion of a hydrocarboncontaining formation, wherein the portion has an average permeability ofless than about 10 millidarcy, comprising: providing heat from one ormore heat sources to the formation; allowing the heat to transfer fromone or more of the heat sources to a selected first section of theformation such that heat from the heat sources creates a pyrolysis zonewherein at least some hydrocarbons are pyrolyzed within the firstselected section, and allowing the heat to transfer from one or more ofthe heat sources to a selected second section of the formation such thatheat from the heat sources heats at least some hydrocarbons within theselected second section to a temperature less than the averagetemperature within the pyrolysis zone; and producing a mixturecomprising hydrocarbons from the formation.
 5352. The method of claim5351, wherein the one or more heat sources comprise at least two heatsources, and wherein superposition of heat from the at least two heatsources pyrolyzes at least some hydrocarbons within the selected firstsection of the formation, and wherein superposition of heat from the atleast two heat sources heats at least some hydrocarbons within theselected second section to a temperature less than the averagetemperature within the pyrolysis zone.
 5353. The method of claim 5351,wherein at least some heated hydrocarbons within the selected secondsection flow into the pyrolysis zone.
 5354. The method of claim 5351,wherein the heat decreases the viscosity of at least some of thehydrocarbons in the selected second section.
 5355. The method of claim5351, further comprising allowing heat to transfer from at least one ofthe heat sources to the selected first section to create thermalfractures in the formation, wherein the thermal fractures substantiallyincrease the permeability of the selected first section.
 5356. Themethod of claim 5351, further comprising allowing heat to transfer fromat least one of the heat sources to the selected second section tocreate thermal fractures in the formation, wherein the thermal fracturessubstantially increase the permeability of the selected second section.5357. The method of claim 5351, wherein the heat is provided such thatan average temperature in the selected first section ranges fromapproximately about 270° C. to about 375° C.
 5358. The method of claim5351, wherein the heat is provided such that an average temperature inthe selected second section ranges from approximately about 180° C. toabout 250° C.
 5359. The method of claim 5351, wherein a viscosity of atleast some of the hydrocarbons in the selected second section rangesfrom approximately about 20 centipoise to about 1000 centipoise. 5360.The method of claim 5351, wherein at least one of the heat sourcescomprises an electrical heater located in the formation.
 5361. Themethod of claim 5351, wherein at least one of the heat sources islocated in a heater well, and wherein at least one of the heater wellscomprises a conduit located in the formation, and further comprisingheating the conduit by flowing a hot fluid through the conduit. 5362.The method of claim 5351, further comprising: monitoring a compositionof the produced mixture; and controlling a pressure in at least aportion of the formation to control the composition of the producedmixture.
 5363. The method of claim 5362, wherein the pressure iscontrolled by a valve proximate to a location where the mixture isproduced.
 5364. The method of claim 5362, wherein the pressure iscontrolled such that pressure proximate to one or more of the heatsources is greater than a pressure proximate to a location where thefluid is produced.
 5365. The method of claim 5361, wherein the pressurein the selected second section is substantially greater than thepressure in the selected first section.
 5366. The method of claim 5351,wherein at least some of the heat sources are arranged in a triangularpattern.
 5367. The method of claim 5351, wherein an average distancebetween heat sources in the selected first section is less than anaverage distance between heat sources in the selected second section.5368. The method of claim 5351, wherein the heat is provided to theselected first section before heat is provided to the selected secondsection.
 5369. The method of claim 5351, wherein the selected firstsection comprises at least one production well.
 5370. The method ofclaim 5351, wherein an average distance between heat sources in theselected first section is between about 2 m to about 10 m.
 5371. Themethod of claim 5351, wherein an average distance between heat sourcesin the selected second section is between about 5 m to about 20 m. 5372.The method of claim 5351, wherein the selected first section comprises aplanar region.
 5373. The method of claim 5351, wherein at least one rowof the heat sources provides heat to the planar region.
 5374. The methodof claim 5373 wherein a length of a row is between about 75 m to about125 m.
 5375. The method of claim 5372, wherein the planar regioncomprises a vertical hydraulic fracture.
 5376. The method of claim 5375,wherein a width of the vertical hydraulic fracture is between about 0.3cm to about 2.5 cm.
 5377. The method of claim 5375, wherein a length ofthe vertical hydraulic fracture is between about 75 m to about 125 m.5378. The method of claim 5351, wherein at least one ring comprising theheat sources provides heat to the selected first section.
 5379. Themethod of claim 5378, wherein at least one ring comprising the heatsources provides heat to the selected second section.
 5380. The methodof claim 5378, wherein the ring comprises a polygon.
 5381. The method ofclaim 5378, wherein the ring comprises a regular polygon.
 5382. Themethod of claim 5378, wherein the ring comprises a hexagon.
 5383. Themethod of claim 5378, wherein the ring comprises a triangle.
 5384. Amethod for treating hydrocarbons in at least a portion of a hydrocarboncontaining formation, wherein the portion has an average permeability ofless than about 10 millidarcy, comprising: providing heat from three ormore heat sources to the formation; allowing the heat to transfer fromthree or more of the heat sources to a selected section of the formationsuch that heat from the heat sources pyrolyzes at least somehydrocarbons within the selected section, and at least three of the heatsources are arranged in a substantially triangular pattern; andproducing a mixture comprising hydrocarbons from the formation. 5385.The method of claim 5384, wherein superposition of heat from at leastthe three heat sources pyrolyzes at least some hydrocarbons within theselected section of the formation.
 5386. The method of claim 5384,wherein the mixture is produced from a production well located in atriangular region created by at least three heat sources.
 5387. Themethod of claim 5384, further comprising allowing heat to transfer fromat least one of the heat sources to the selected section to createthermal fractures in the formation, wherein the thermal fracturessubstantially increase the permeability of the selected section. 5388.The method of claim 5384, wherein the heat is provided such that anaverage temperature in the selected section ranges from approximatelyabout 270° C. to about 375° C.
 5389. The method of claim 5384, whereinat least one of the heat sources comprises a electrical heater locatedin the formation.
 5390. The method of claim 5384, wherein at least oneof the heat sources is located in a heater well, and wherein at leastone of the heater wells comprises a conduit located in the formation,and further comprising heating the conduit by flowing a hot fluidthrough the conduit.
 5391. The method of claim 5384, wherein at leastsome of the heat sources are arranged in a triangular pattern.
 5392. Themethod of claim 5384, further comprising: monitoring a composition ofthe produced mixture; and controlling a pressure in at least a portionof the formation to control the composition of the produced mixture.5393. The method of claim 5392, wherein the pressure is controlled by avalve proximate to a location where the mixture is produced.
 5394. Themethod of claim 5392, wherein the pressure is controlled such thatpressure proximate to one or more of the heat sources is greater than apressure proximate to a location where the fluid is produced.
 5395. Themethod of claim 5384, wherein an average distance between heat sourcesis between about 2 m to about 8 m.